10-K

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¨Noý

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
Glossary of Oil and Natural Gas Terms	ii
Glossary of Certain Other Terms	v
Cautionary Statement Regarding Forward-Looking Statements	vi
PART I
Items 1 and 2. Business and Properties	1
Item 1A. Risk Factors	15
Item 1B. Unresolved Staff Comments	39
Item 3. Legal Proceedings	39
Item 4. Mine Safety Disclosures	39
PART II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	40
Item 6. Selected Financial Data	41
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	44
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	57
Item 8. Financial Statements and Supplementary Data	58
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58
Item 9A. Controls and Procedures	58
Item 9B. Other Information	61
PART III
Item 10. Directors, Executive Officers and Corporate Governance	61
Item 11. Executive Compensation	66
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	70
Item 13. Certain Relationships and Related Transactions, and Director Independence	73
Item 14. Principal Accountant Fees and Services	76
PART IV
Item 15. Exhibits and Financial Statement Schedules	77
Signatures	S-1

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 under “Item 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 $77.41per Bbl and the Henry Hub spot market price of natural gas ranged from$2.49 to $6.24per MMBtu. OnJanuary 28, 2019, the WTI posted price for crude oil was$51.79per 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.

Approximately28%of our total estimated proved reserves as ofDecember 31, 2018were 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 reservesare 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

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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.

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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.

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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

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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

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	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.

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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

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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.

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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.

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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.

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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	)

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	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, 2017and2016

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

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	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.

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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.

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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 within60days 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
					(in thousands)
May 2, 2016	Q1 2016	$	0.149	May 23, 2016	$	10,497
July 21, 2016	Q2 2016	$	0.189	August 22, 2016	$	13,693
October 25, 2016	Q3 2016	$	0.207	November 18, 2016	$	14,997
February 3, 2017	Q4 2016	$	0.258	February 24, 2017	$	18,692
April 28, 2017	Q1 2017	$	0.302	May 25, 2017	$	21,880
July 28, 2017	Q2 2017	$	0.332	August 24, 2017	$	24,286
October 16, 2017	Q3 2017	$	0.337	November 14, 2017	$	24,652
January 31, 2018	Q4 2017	$	0.460	February 26, 2018	$	33,649
April 5, 2018	Q1 2018	$	0.480	April 27, 2018	$	35,112
July 27, 2018	Q2 2018	$	0.600	August 20, 2018	$	43,901
October 23, 2018	Q3 2018	$	0.580	November 19, 2018	$	42,447
January 30, 2019	Q4 2018	$	0.510	February 25, 2019	*

* The Q4 2018 distribution is payable on February 25, 2019 to unitholders of record at the close of business on February 19, 2019. Based on the common units and Operating Company units held by Diamondback on February 5, 2019, the Q4 2018 distribution payable to Diamondback on February 25, 2019 will be approximately $37.3 million.

July 2018 Equity Offering

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.

Our Credit Agreement

On July 8, 2014, we entered into a secured revolving credit agreement, or revolving credit facility, with Wells Fargo, as administrative agent, certain other lenders, and the Operating Company as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and we became a guarantor of the credit agreement. On July 20, 2018, we, the Operating Company, Wells Fargo and the other lenders amended and restated the credit agreement to reflect its

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assumption by the Operating Company. The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”) of $555.0 million, subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. 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.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of our and our subsidiary’s assets.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

As of December 31, 2018, the Operating Company was in compliance with all financial covenants under its credit agreement. The lenders may accelerate all of the indebtedness under the Operating Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of our credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Cash Flows

The following table presents our cash flows for the period indicated:

	Year Ended December 31,
	2018			2017			2016
	(in thousands)
Cash Flow Data:
Net cash provided by operating activities	$	244,493		$	139,219		$	68,627
Net cash used in investing activities	(614,253		)	(344,079		)	(205,721		)
Net cash provided by financing activities	368,239			219,844			145,768
Net increase (decrease) in cash	$	(1,521	)	$	14,984		$	8,674

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Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volume of oil and natural gas sold by our producers. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

Investing Activities

Net cash used in investing activities was $614.3 million, $344.1 million and $205.7 million during the years ended December 31, 2018, 2017 and 2016, respectively, related to acquisitions of oil and natural gas interests and land.

Financing Activities

Net cash provided by financing activities was $368.2 million during the year ended December 31, 2018, primarily related to proceeds from net borrowings under our credit facility of $317.5 million and net proceeds from our public offerings of common units of $303.1 million, partially offset by distributions to our unitholders of $253.5 million during 2018.

Net cash provided by financing activities was $219.8 million during the year ended December 31, 2017, primarily related to aggregate net proceeds of $380.0 million from our public offerings of common units in January and July 2017, partially offset by $130.9 million of distributions to our unitholders and $27.0 million of net repayments under our revolving credit agreement during 2017.

Net cash provided by financing activities was $145.8 million during the year ended December 31, 2016 primarily related to $86.0 million of net borrowings under our revolving credit agreement and net proceeds of $125.0 million from our public offering of common units partially offset by $64.8 million of distributions to our unitholders during 2016.

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2018:

	Payments Due by Period
	Total		2019		2020-2021		2022-2023		Thereafter
	(in thousands)
Credit agreement(1)	$	411,000	$	—	$	—	$	411,000	$	—
Interest and commitment fees under our credit agreement(2)	$	2,070	$	540	$	1,080	$	450	$	—
	$	413,070	$	540	$	1,080	$	411,450	$	—

(1) Includes the outstanding principal amount under the credit agreement, the table does not include interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.

(2) This table reflects only the minimum amount of interest and commitment fees due, which as of December 31, 2018 includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of our credit agreement. The table does not include interest expense as we cannot predict the timing of future borrowings and repayments or interest rates to be charged. See Note 5–Debt to our consolidated financial statements and related notes included elsewhere in this Annual Report.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See the notes to our consolidated financial statements included elsewhere in this Annual Report for additional information regarding these accounting policies.

Use of Estimates

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with

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certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, unit–based compensation and estimate of income taxes.

Method of Accounting for Oil and Natural Gas Properties

We account for 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. 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.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Oil and Natural Gas Reserve Quantities and Standardized Measure of Discounted Future Net Cash Flows

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net cash flows. The SEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Royalty Interest and Revenue Recognition

Royalty interests represent the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when control passes to the producer.

Holders of royalty interests have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development and operation of the property.

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Impairment

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, impairment and deferred income taxes exceed the discounted future net revenues of proved oil and natural gas reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil and natural gas prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.

Accounting for Unit-Based Compensation

Unit-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. The LTIP and related accounting policies are defined and described more fully in Note 7–Unit-Based Compensation to our audited consolidated financial statements included elsewhere in this Annual Report. The determination of the fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the expected life of the award and forfeiture rate assumptions. Estimates of the fair value of unit options granted during the year ended December 31, 2018, were completed using a Black-Scholes option valuation model, which requires us to make several assumptions.

Investments

We have an equity interest in a limited partnership that is so minor that we have no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method. Effective January 1, 2018, we adopted Accounting Standards Update 2016-01 which requires us to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. For the year endedDecember 31, 2018, we recorded a loss of $0.6 million, which then decreased our investment balance to $14.5 million, which is included in other assets in the accompanying consolidated balance sheets.

Income Taxes

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. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

We are subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 10—Income Taxes of our consolidated financial statements included elsewhere in the Annual Report. In addition to the 2018 tax year, our 2015 through 2017 tax years, during which we were treated as a pass-through entity for federal income tax purposes, remain open to examination by tax authorities. As of December 31, 2018 and December 31, 2017, we had no unrecognized tax benefits that would have a material impact on the effective tax rate. We are continuing our practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2018, 2017 and 2016, there was no interest or penalties associated with uncertain tax positions recognized in our consolidated financial statements.

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions

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that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. We adopted this standard effective January 1, 2018 using the modified retrospective method. We utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standard on its total revenues, operating income and our consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. We adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. We adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. We adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on our financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of December 31, 2018, we were not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. We will adopt this standard effective January 1, 2019 using the modified retrospective method. The adoption of this standard will not have an effect on our financial position, results of operations or liquidity.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. We adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on our financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. We adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on our financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on our financial position, results of operations or liquidity.

In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable

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payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. We adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on our financial position, results of operations or liquidity.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. We adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on our financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. We adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on our financial position, results of operations or liquidity.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have an impact on our financial statements since it does not have a history of credit losses.

In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have an impact on our financial statements since we do not have a history of credit losses.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2018, 2017 and 2016. Although the impact of inflation has been insignificant in recent years, it continues to be a factor in the U.S. economy and our operators do experience inflationary pressure on the costs of oilfield services and equipment as drilling activity increases in the areas in which our properties are located.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable, particularly during the past year, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.

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Credit Risk

We are subject to risk resulting from the concentration of royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2018, three purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (US) Company, or Shell Trading (31%), Concho Resources, Inc. (16%) and Trafigura Trading LLC (11%). For the year ended December 31, 2017, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (47%) and RSP Permian LLC (23%). For the year ended December 31, 2016, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (57%) and RSP Permian LLC (32%). We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our credit agreement. The terms of our credit agreement provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus0.50% and 3-month LIBOR plus1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from0.75% to 1.75%in the case of the alternative base rate and from1.75% to 2.75%per annum in the case of LIBOR, in each case depending on the amount of the loans outstanding in relation to the borrowing base. We entered into this credit agreement on July 8, 2014, as subsequently amended and restated, and as of December 31, 2018, we had $411.0 million in outstanding borrowings. Our weighted average interest rate was 4.34%. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $4.1 million based on the $411.0 million outstanding in the aggregate under our credit agreement on December 31, 2018.

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item appears beginning on page F-1 of this report.

ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures. Under the direction of the Chief Executive Officer and Chief Financial Officer of our general partner, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our general partner, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2018, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner have concluded that as of December 31, 2018, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the year ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting of the Partnership. The Partnership’s internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer and Chief Financial Officer of our general partner to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Partnership’s financial statements for external purposes in accordance with generally accepted accounting principles.

Management conducted an evaluation of the effectiveness of the Partnership’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Partnership’s internal control over financial reporting and determined that the Partnership maintained effective internal control over financial reporting as of December 31, 2018.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Partnership included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Partnership’s internal control over financial reporting at December 31, 2018. The report, which expresses an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting at December 31, 2018, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners

Viper Energy Partners LP

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Viper Energy Partners LP (a Delaware limited partnership) and subsidiary (collectively, the “Partnership”) as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2018, and our report dated February 15, 2019 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 15, 2019

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ITEM 9B.     OTHER INFORMATION

None.

PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management of Viper Energy Partners LP

We are managed and operated by the board of directors and executive officers of our general partner, the latter of whom are employed by Diamondback.

Diamondback owns all the membership interests in our general partner. As a result of owning our general partner, Diamondback has the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders are not entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owner.

The executive officers of our general partner manage the day-to-day affairs of our business. All of the executive officers of our general partner also serve as executive officers of Diamondback. The executive officers listed below allocate their time between managing our business and the business of Diamondback.

Executive Officers and Directors of Our General Partner

The following table shows information for the executive officers and directors of our general partner as of January 31, 2019. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers.

Name	Age	Position With Our General Partner
Travis D. Stice	57	Chief Executive Officer, Director
Kaes Van't Hof	32	President
Teresa L. Dick	49	Chief Financial Officer, Executive Vice President and Assistant Secretary
Russell Pantermuehl	59	Executive Vice President—Reservoir Engineering
Thomas F. Hawkins	64	Senior Vice President—Land
Randall J. Holder	65	Executive Vice President, General Counsel and Secretary
Paul S. Molnar	62	Executive Vice President—Exploration and Business Development
Steven E. West	58	Executive Chairman, Director
W. Wesley Perry	63	Director
Spencer D. Armour	64	Director
Michael L. Hollis	43	Director
James L. Rubin	34	Director
Rosalind Redfern Grover	77	Director

Travis D. Stice. Mr. Stice has served as Chief Executive Officer and a director of our general partner since February 2014. He has served as Chief Executive Officer of Diamondback since January 2012 and as a director since November 2012. Prior to his positions with us and Diamondback, Mr. Stice served as its President and Chief Operating Officer from April 2011 to January 2012. From November 2010 to April 2011, Mr. Stice served as a Production Manager of Apache Corporation, an oil and gas exploration company. Mr. Stice served as a Vice President of Laredo Petroleum Holdings, Inc., an oil and gas exploration company, from September 2008 to September 2010 and as a Development Manager of ConocoPhillips/Burlington Resources Mid-Continent Business Unit, an oil and gas exploration company, from April 2006 until August 2008. Prior to that, Mr. Stice held a series of positions at Burlington Resources, an oil and gas exploration company, most recently as a General Manager, Engineering, Operations and Business Reporting of its Mid Continent Division from January 2001 until Burlington Resources’ acquisition by ConocoPhillips in March 2006. Mr. Stice has over 26 years of experience in production operations, reservoir engineering, production engineering and unconventional oil and gas exploration and over 18 years of management experience. Mr. Stice graduated from

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Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. He is a registered engineer in the State of Texas, and is a 25-year member of the Society of Petroleum Engineers.

We believe Mr. Stice’s expertise and extensive industry and executive management experience, including at Diamondback, make him a valuable asset to the board of directors of our general partner.

Kaes Van’t Hof. Mr. Van't Hof has served as President of our general partner since March 2017. Mr. Van't Hof joined Diamondback in July 2016 as Vice President—Strategy and Corporate Development and was promoted to Senior Vice President-Strategy and Corporate Development in February 2017. Prior to his positions with us and Diamondback, Mr. Van't Hof served as Chief Executive Officer for Bison Drilling and Field Services from September 2012 to June 2016. From August 2011 to August 2012, Mr. Van't Hof was an analyst for Wexford Capital LP responsible for developing operating models and business plans, including in connection with our initial public offering, and before that worked for the Investment Banking-Financial Institutions Group of Citigroup Global Markets, Inc. from February 2010 to August 2011. Mr. Van't Hof was a professional tennis player from May 2008 to January 2010. Mr. Van't Hof received a Bachelor of Science in Accounting and Business Administration from the University of Southern California.

Teresa L. Dick. Ms. Dick has served as Chief Financial Officer, Executive Vice President and Assistant Secretary of our general partner since February 2017 and served as Chief Financial Officer, Senior Vice President and Assistant Secretary from February 2014 to February 2017. She has also served as Diamondback's Executive Vice President and Chief Financial Officer since February 2017, as its Assistant Secretary since October 2012, as its Chief Financial Officer and Senior Vice President from November 2009 to February 2017 and as its Corporate Controller from November 2007 until November 2009. From June 2006 to November 2007, Ms. Dick held a key management position as the Controller/Tax Director at Hiland Partners, a publicly traded midstream energy master limited partnership. Ms. Dick has over 19 years of accounting experience, including over eight years of public company experience in both audit and tax areas. Ms. Dick received her Bachelor of Business Administration degree in Accounting from the University of Northern Colorado. She is a certified public accountant and a member of the American Institute of CPAs and the Council of Petroleum Accountants Societies.

Russell Pantermuehl. Mr. Pantermuehl has served as Executive Vice President—Reservoir Engineering of our general partner since February 2017 and served as Vice President—Reservoir Engineering from February 2014 to February 2017. He has also served as Diamondback's Executive Vice President-Reservoir Engineering since February 2017, and served as Vice President-Reservoir Engineering from August 2011 to February 2017. Prior to his positions with us and Diamondback, Mr. Pantermuehl served as a reservoir engineering supervisor for Concho Resources Inc., an oil and gas exploration company, from March 2010 to August 2011. Mr. Pantermuehl worked for ConocoPhillips Company as a reservoir engineering advisor from January 2005 to March 2010. Mr. Pantermuehl also worked as an independent consultant in the oil and gas industry from March 2000 to December 2004. He received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.

Thomas F. Hawkins. Mr. Hawkins has served as Senior Vice President—Land of our general partner since March 2017. He has also served as Diamondback's Senior Vice President-Land since March 2017. Prior to his positions with us and Diamondback, Mr. Hawkins was an independent consultant for land activities from July 2016 to February 2017. Mr. Hawkins has over 38 years of experience in the oil and gas industry. Mr. Hawkins spent seven years with Oasis Petroleum Inc., an oil and gas company, as its Senior Vice President of Land or in related capacities from March 2009 to June 2016. Until February 2009, Mr. Hawkins spent 31 years with ConocoPhillips and Burlington Resources (which ConocoPhillips acquired in 2006). During that time, Mr. Hawkins held various operations and managerial positions in the land, marketing, planning and the corporate acquisitions and divestitures groups. Mr. Hawkins has worked in several major regions in the continental United States, including the San Juan Basin, the Williston Basin and the Austin Chalk/Wilcox Trends in South Texas. Mr. Hawkins holds a Bachelor of Business Administration in Finance from the University of Texas at El Paso.

Randall J. Holder. Mr. Holder has served as Executive Vice President, General Counsel and Secretary of our general partner since February 2017 and served as Vice President, General Counsel and Secretary from February 2014 to February 2017. He has also served as Diamondback's Executive Vice President, General Counsel and Secretary since February 2017, and served as its Vice President, General Counsel and Secretary from October 2012 to February 2017, and as General Counsel and Vice President from November 2011 to October 2012. Prior to his positions with us and Diamondback, Mr. Holder served as General Counsel and Vice President for Great White Energy Services LLC, an oilfield services company, from November 2008 to November 2011. He served as Executive Vice President and General Counsel for R.L. Hudson and Company, a supplier of molded rubber and plastic components, from February 2007 to October 2008. He was in private practice of law and a member of Holder Betz LLC from February 2005 to February 2007. Mr. Holder served as Vice President and Assistant General Counsel for Dollar Thrifty Automotive Group, a vehicle rental company, from January 2003 to February 2005 and as Vice President and General Counsel for Thrifty Rent-A-Car System, Inc., a vehicle rental company, from September 1996 to December 2002. He also served as Vice

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President and General Counsel for Pentastar Transportation Group, Inc. from November 1992 to September 1996, which was wholly-owned by Chrysler Corporation. Mr. Holder started his legal career with Tenneco Oil Company where he served as a Division Attorney providing legal services to the company's mid-continent division for ten years. He received a Juris Doctorate degree from Oklahoma City University.

Paul S. Molnar. Mr. Molnar has served as our Executive Vice President-Exploration and Business Development since January 2017 and served as our Vice President-Geoscience from February 2014 to January 2017. Mr. Molnar joined Diamondback in August 2011 as Vice President-Geoscience and was promoted to Executive Vice President-Exploration and Business Development effective January 1, 2017. Prior to joining us and Diamondback, Mr. Molnar served as a Senior District Geologist for Samson Investment Company, an oil and gas exploration company, from March 2011 to August 2011. Mr. Molnar worked as an asset supervisor and geosciences supervisor for ConocoPhillips Company from April 2006 to February 2011. Mr. Molnar also worked as a geologic advisor for Burlington Resources, an oil and gas exploration company, from December 1996 to March 2006. Mr. Molnar has over 31 years of industry experience. Mr. Molnar received a Bachelor of Science degree in Geoscience from the State University of New York, College at Buffalo and a Master of Science degree in Geology from the State University of New York, University at Buffalo.

Steven E. West. Mr. West has served as a director and Executive Chairman of our general partner since February 2014. Mr. West has also served as a director of Diamondback since December 2011 and as its Chairman of the Board since October 2012. He served as Diamondback's Chief Executive Officer from January 1, 2009 to December 31, 2011. From January 2011 until December 2016, Mr. West was a partner at Wexford Capital LP, focusing on Wexford's private equity energy investments. From August 2006 until December 2010, Mr. West served as senior portfolio advisor at Wexford. From August 2003 until August 2006, he was the chief financial officer of Sunterra Corporation, a former Wexford portfolio company. From December 1993 until July 2003, Mr. West held senior financial positions at Coast Asset Management and IndyMac Bank. Prior to that, he worked at First Nationwide Bank, Lehman Brothers and Peat Marwick Mitchell & Co., the predecessor of KPMG LLP. Mr. West holds a Bachelor of Science degree in Accounting from California State University, Chico.

We believe that Mr. West’s background in finance, accounting and private equity energy investments, as well as his executive management skills developed as part of his career with Wexford, its portfolio companies and other financial institutions qualify him to serve on the board of directors of our general partner.

W. Wesley Perry. Mr. Perry has been a member of the board of directors of our general partner since June 2014. Mr. Perry has served as a director of Genie Energy Ltd., an independent retail energy provider, since October 2011, currently serves as the chair of its audit committee and a member of its compensation, nominating, corporate governance and technology committees and has served as the chairman of the board of directors of Genie Energy International Corporation since September 2009. Mr. Perry also serves as manager of PBEX, LLC, an oil and gas exploration and development company, a position he has held since July 2012. Mr. Perry has served as manager of S.E.S. Investments, Ltd., an oil and gas investment company, since 1985. He has served as Chief Executive Officer of E.G.L. Resources, Inc., an oil and gas production company, since July 2008 and served as its President from 2003 to July 2008. Mr. Perry was a director of UTG, Inc., an insurance holding company, from 2001 to 2013 and served on its Audit Committee. Mr. Perry served on the Midland City Council from 2002 to 2008 and as Mayor of Midland from 2008 through 2014. He is the President of the Milagros Foundation and a trustee of the Abell-Hangar Foundation. He has a Bachelor of Science degree in Engineering from the University of Oklahoma.

We believe that Mr. Perry’s extensive experience in the oil and gas industry and his strong financial background qualify him to serve on the board of directors of our general partner.

Spencer D. Armour. Mr. Armour has been a member of the board of directors of our general partner since July 2017.Mr. Armour has over 30 years of executive and entrepreneurial experience in the energy services industry. Mr. Armour has served as a partner of Geneses Investments since January 2019. He served as President of PT Petroleum LLC in Midland, Texas from March 2013 until January 2019. He was the Vice President of Corporate Development for Basic Energy Services, Inc. from 2007 to 2008, which acquired Sledge Drilling Corp., a company Mr. Armour co-founded and served as Chief Executive Officer for from 2005 to 2006. From 1998 through 2005, he served as Executive Vice President of Patterson-UTI Energy, Inc., which acquired Lone Star Mud, Inc., a company Mr. Armour founded and served as President from 1986 to 1997. Mr. Armour has served as a director of ProPetro Holding Corp. since February 2013 and as a director of CES Energy since December 2018. Mr. Armour also served on the Patterson-UTI Board of Directors from 1999 through 2001. Mr. Armour received a Bachelor of Science in Economics from the University of Houston and was appointed to the University of Houston System Board of Regents in 2011 by former Texas Governor Rick Perry.

We believe that Mr. Armour’s extensive experience in the oil and gas industry qualify him to serve on the board of directors of our general partner.

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Michael L. Hollis. Mr. Hollis has been a member of the board of directors of our general partner since June 2014. He has served as Diamondback’s President since January 2017, Chief Operating Officer since July 2015 and as director since April 2018. He also served as Vice President-Drilling of Diamondback from September 2011 until July 2015. Prior to his positions with Diamondback, Mr. Hollis served in various roles, most recently as drilling manager at Chesapeake Energy Corporation, an oil and gas exploration company, from June 2006 to September 2011. He worked for ConocoPhillips Company as a senior drilling engineer from January 2002 to June 2006 and as a process engineer from 2001 to 2003. Mr. Hollis also worked as a production engineer for Burlington Resources from 1998 to 2001 as well as from June 2003 to January 2004. Mr. Hollis received his Bachelor of Science degree in Chemical Engineering from Louisiana State University.

We believe that Mr. Hollis’ extensive experience in the oil and gas industry, including at Diamondback, qualifies him to serve on the board of directors of our general partner.

James L. Rubin. Mr. Rubin has been a member of the board of directors of our general partner since June 2014. He has served as a partner at Wexford since 2012 and currently serves as Portfolio Manager and Co-Head of Equities and as a member of Wexford’s hedge fund investment committee. From 2006 to 2012, he served as an analyst and later as Vice President, focusing on Wexford’s public and private energy investments. Mr. Rubin graduated cum laude from Yale University with a Bachelor of Arts degree with honors in political science and economics.

We believe that Mr. Rubin’s strong financial background qualifies him to serve on the board of directors of our general partner.

Rosalind Redfern Grover. Ms. Grover has been a member of the board of directors of our general partner since December 2014. Ms. Grover served as Chairman of the Board of Flag-Redfern Oil Company until the company was sold to Kerr-McGee Corporation in 1988. She has served as the President of Redfern Enterprises, Inc., an independent oil and gas producer, since 1989 and as the Chief Executive Officer of Redfern & Grover Resources, LLC, an independent oil and gas producer, since 2014. Ms. Grover holds Bachelors and Masters degrees from the University of Arizona.

We believe that Ms. Grover’s extensive experience in the oil and gas industry, including with oil and gas partnerships, qualifies her to serve on the board of directors of our general partner.

Director Independence

The board of directors of our general partner has seven directors, three of whom are independent as defined under the independence standards established by Nasdaq and the Exchange Act. W. Wesley Perry, Spencer D. Armour and Rosalind Redfern Grover serve as the independent members of the board of directors of our general partner. Nasdaq does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by Nasdaq and the Exchange Act.

Board Leadership Structure and Role in Risk Oversight

Leadership of our general partner’s board of directors is vested in the Executive Chairman. Steven E. West serves as the Executive Chairman of the board of directors of our general partner and as Chairman of the board of Diamondback. Our general partner’s board of directors has determined that the combined roles of Executive Chairman of the board of directors of our general partner and Chairman of the board of Diamondback allows the board of directors to take advantage of the leadership skills of Mr. West and that Mr. West’s in-depth knowledge of, and experience in, our business, history, structure and organization facilitates timely communications between the board of directors of Diamondback and the board of directors of our general partner.

As a partnership engaged in the oil and natural gas industry, we face a number of risks, including risks associated with supply of and demand for oil and natural gas, volatility of oil and natural gas prices, exploring for, developing, producing and delivering oil and natural gas, declining production, environmental and other government regulations and taxes, weather conditions that can affect oil and natural gas operations over a wide area, adequacy of our insurance coverage, political instability or armed conflict in oil and natural gas producing regions and the overall economic environment. Management is responsible for the day-to-day management of risks we face as a partnership, while the board of directors of our general partner, as a whole and through its committees, has responsibility for the oversight of risk management. In its risk oversight role, the board of directors of our general partner has the responsibility to satisfy itself that the risk management processes designed and implemented by management are adequate and functioning as designed.

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The board of directors of our general partner believes that full and open communication between management and the board is essential for effective risk management and oversight. The Executive Chairman of the board of directors of our general partner meets regularly with the Chief Executive Officer and the Chief Financial Officer to discuss strategy and risks facing the partnership. Executive officers may attend the board meetings of our general partner and are available to address any questions or concerns raised by the board on risk management-related and any other matters. Other members of our management team periodically attend the board meetings or are otherwise available to confer with the board to the extent their expertise is required to address risk management matters. Periodically, the board of directors of our general partner receives presentations from senior management on strategic matters involving our operations. During such meetings, the board also discusses strategies, key challenges, and risks and opportunities for the partnership with senior management.

While the board of directors of our general partner is ultimately responsible for risk oversight at the partnership, its two committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. The audit committee assists the board in fulfilling its oversight responsibilities with respect to risk management in the areas of financial reporting, internal controls and compliance with legal and regulatory requirements, and discusses policies with respect to risk assessment and risk management. The conflicts committee assists the board in fulfilling its oversight responsibilities with respect to specific matters that the board believes may involve conflicts of interest.

Meetings of the Board of Directors

During 2018, the board of directors of our general partner met three times. Each director attended at least 86% of the meetings of the board and the committees of the board on which he or she served that occurred during 2018.

Communications with Directors

Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: c/o Secretary, Viper Energy Partners LP, 500 West Texas, Suite 1200, Midland, Texas. Communications are distributed to the board of directors, committee of the board of directors, or director as appropriate, depending on the facts and circumstances outlined in the communication. Commercial solicitations or communications will not be forwarded.

Committees of the Board of Directors

The board of directors of our general partner has an audit committee and a conflicts committee. We do not have a compensation committee or a nominating and corporate governance committee. Rather, the board of directors of our general partner has authority over compensation matters and nominating and corporate governance matters.

Audit Committee

The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the audit committee and our management, as necessary. The audit committee met four times during 2018. The audit committee has adopted a charter, which is available on our website under the “corporate governance” section at http://ir.viperenergy.com.

W. Wesley Perry, Spencer D. Armour and Rosalind Redfern Grover currently serve on the audit committee, and Mr. Perry serves as the chairman. The board or directors of our general partner has determined that each of W. Wesley Perry, Spencer D. Armour and Rosalind Redfern Grover meet the independence and experience standards established by Nasdaq and the Exchange Act and that Mr. Perry is an “audit committee financial expert” as defined under SEC rules.

Conflicts Committee

Our conflicts committee reviews specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partner or directors,

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officers or employees of its affiliates, including Diamondback, and must meet the independence standards established by Nasdaq and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. W. Wesley Perry, Spencer D. Armour and Rosalind Redfern Grover are the members of the conflicts committee, which was formed in January 2015.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act, to file reports of beneficial ownership and reports of changes in beneficial ownership of such securities with the SEC. Directors, officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of all Section 16(a) forms they file with the SEC.

Based solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of our general partner, we believe that during the year ended December 31, 2018 the officers and directors of our general partner and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a).

Corporate Governance

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics, or Code of Ethics, that applies to all employees, including executive officers, and directors. Amendments to or waivers from the Code of Ethics will be disclosed on our website. We have also made the Code of Ethics available on our website under the “Corporate Governance” section at http://ir.viperenergy.com.

Reimbursement of Expenses of our General Partner

Our partnership agreement requires us to reimburse our general partner and its affiliates, including Diamondback, for all expenses they incur and payments they make on our behalf in connection with operating our business. Our 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 partnership agreement provides that our general partner will determine the expenses that are allocable to us.

ITEM 11.     EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

As is commonly the case for publicly traded limited partnerships, we have no officers. Our general partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. Our general partner’s executive officers are employed and compensated by Diamondback or a subsidiary of Diamondback. All of the executive officers that are responsible for managing our day-to-day affairs are also current executive officers of Diamondback.

All of the executive officers of our general partner have responsibilities to both us and Diamondback and allocate their time between managing our business and managing the business of Diamondback. Since all of these executive officers are employed by Diamondback or one of its subsidiaries, the responsibility and authority for compensation-related decisions for them resides with Diamondback’s compensation committee. Diamondback has the ultimate decision-making authority with respect to the total compensation of the executive officers that are employed by Diamondback including, subject to the terms of the partnership agreement, the portion of that compensation that is allocated to us pursuant to Diamondback’s allocation methodology. Any such compensation decisions are not subject to any approvals by the board of directors of our general partner or any committees thereof. However, all determinations with respect to awards that are made to executive officers, key employees and non-employee directors under the LTIP are made by the board of directors of our general partner. Please see the description of the LTIP below under the heading “Long-Term Incentive Plan.”

The executive officers of our general partner, as well as the employees of Diamondback who provide services to us, may participate in employee benefit plans and arrangements sponsored by Diamondback, including plans that may be established in the future. Certain of our general partner’s executive officers and employees and certain employees of Diamondback who provide services to us currently hold grants under Diamondback’s equity incentive plans. Except with respect to any awards that may be

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granted under the LTIP, the executive officers of our general partner do not receive separate amounts of compensation in relation to the services they provide to us. In accordance with the terms of our partnership agreement, we reimburse Diamondback for compensation related expenses attributable to the portion of the executive’s time dedicated to providing services to us. Although we bear an allocated portion of Diamondback’s costs of providing compensation and benefits to employees who serve as executive officers of our general partner, we have no control over such costs and did not establish and do not direct the compensation policies or practices of Diamondback. Except with respect to awards granted under the LTIP, compensation paid or awarded by us in 2018 consisted only of the portion of compensation paid by Diamondback that is allocated to us and our general partner pursuant to Diamondback’s allocation methodology and subject to the terms of the partnership agreement.

A full discussion of the compensation programs for Diamondback’s executive officers and the policies and philosophy of the compensation committee of Diamondback’s board of directors will be set forth in Diamondback’s 2019 proxy statement under the heading “Compensation Discussion and Analysis.” Specifically, compensation paid directly by us through our LTIP or indirectly by us through reimbursement pursuant to our partnership agreement will be included in the amounts set forth in certain of the tables set forth in Diamondback’s 2019 proxy statement, with awards outstanding pursuant to our LTIP separately identified.

Long-Term Incentive Plan

In order to incentivize our management and directors to continue to grow our business, the board of directors of our general partner adopted the LTIP for employees, officers, consultants and directors of our general partner and any of its affiliates, including Diamondback, who perform services for us.

The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. We will be responsible for the cost of awards granted under the LTIP.

During 2018, our general partner made grants under the LTIP of phantom units to the non-employee directors of our general partner (see “Director Compensation” below for information regarding those awards). In addition, on February 13, 2018, our general partner granted 48,033 and 53,370 phantom units, respectively, to Messrs. Stice and Van’t Hof under the LTIP, with each such grant vesting in three equal installments beginning on February 16, 2018.

Administration

The LTIP is administered by the board of directors of our general partner pursuant to its terms and all applicable state, federal, or other rules or laws. The board of directors of our general partner has the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP.

Change in Control

Upon a “change in control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the committee deems appropriate to reflect the change in control.

Termination of Employment or Service

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors will be determined by the committee in the terms of the relevant award agreement.

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Compensation Report

Neither we nor the board of directors of our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above. Based on this review and discussion, the board of directors of our general partner has approved the Compensation Discussion and Analysis for inclusion in this Annual Report.

The Board of Directors of Viper Energy Partners GP LLC

Travis D. Stice

Steven E. West

W. Wesley Perry

Spencer D. Armour

Michael L. Hollis

James L. Rubin

Rosalind Redfern Grover

Director Compensation

The executive officers or employees of our general partner or of Diamondback who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not executive officers or employees of our general partner or of Diamondback receive compensation as “non-employee directors” as set by our general partner’s board of directors.

Each non-employee director receives a compensation package that consists of an annual cash retainer of $60,000 plus an additional annual payment of $15,000 for the chairperson and $10,000 for each other member of the audit committee and $10,000 for the chairperson and $5,000 for each other member of each other committee. In addition, each non-employee director receives an equity award of phantom units under the LTIP granted annually at the close of business on July 10th of each year or, if not a business day, the first business day thereafter. The number of phantom units awarded is calculated by dividing $100,000 by the average closing price of our common units for the five trading days immediately proceeding the date of grant. The awards vest on the first anniversary of the grate date. Our directors are also reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees.

Each member of the board of directors of our general partner is indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.

The following table sets forth the aggregate dollar amount of all fees paid to each of the non-employee directors of our general partner during 2018 for their services on the board:

Name	Fees Earned or Paid in cash (a)		Unit Awards (b)		Total
Spencer D. Armour (e)	$	75,000	$	105,153	$	180,153
Rosalind Redfern Grover (c)(d)(e)	75,000		105,153		180,153
W. Wesley Perry (c)(d)(e)	85,000		105,153		190,153
James L. Rubin (c)(d)(e)	60,000		105,153		165,153
Steven E. West (c)(d)(e)	60,000		105,153		165,153

(a) This column reflects the value of a director’s annual retainer.

(b) The amount in this column represents the aggregate grant date fair value of phantom units granted in the fiscal year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, “Compensation - Stock Compensation.” Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.

(c) Each of Ms. Grover and Messrs. Perry, Rubin and West received a grant of 5,424 phantom units on August 24, 2016, of which 1,808 vested and settled on the date of grant, 1,808 vested and settled on June 17, 2017 and 1,808 phantom units vested and settled on June 17, 2018, pursuant to the LTIP, with each unit having a grant date fair value of $16.57. Each phantom unit is the economic equivalent of one of our common units.

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(d) Each of Ms. Grover and Messrs. Armour, Perry, Rubin and West received a grant of 6,414 phantom units on July 25, 2017, which vested and settled on July 1, 2018, pursuant to the LTIP, with each unit having a grant date fair value of $16.78. Each phantom unit is the economic equivalent of one of our common units.

(e) Each of Ms. Grover and Messrs. Armour, Perry, Rubin and West received a grant of 3,063 phantom units on July 10, 2018, which will vest and settle on July 10, 2019, pursuant to the LTIP, with each unit having a grant date fair value of $34.33. Each phantom unit is the economic equivalent of one of our common units.

Messrs. Stice and Hollis are both directors of our general partner, but Mr. Stice is also an executive officer of our general partner and both Messrs. Stice and Hollis are employees of Diamondback E&P LLC. Each of Messrs. Stice and Hollis has received awards pursuant to the LTIP for his service as an executive officer or employee, respectively, and unrelated to his service as directors. These awards are reflected in the tables contained in Diamondback’s 2019 proxy statement under the heading “Compensation Discussion and Analysis.”

Compensation Committee Interlocks and Insider Participation

As previously noted, our general partner’s board of directors is not required to maintain, and does not maintain, a separate compensation committee. Mr. Hollis, a director of our general partner, is also an executive officer of Diamondback. Mr. Stice, a director and executive officer of our general partner, is also a director and executive officer of Diamondback. However, all compensation decisions with respect to Messrs. Stice and Hollis are made by Diamondback and Messrs. Stice and Hollis do not receive any compensation directly from us or our general partner except for awards under our LTIP. As described in “–Compensation Discussion and Analysis,” decisions regarding the compensation of our general partner’s executive officers are made by Diamondback. Please read “Items 1 and 2. Business and Properties–Our Relationship with Diamondback” and “Item 13. Certain Relationships and Related Transactions, and Director Independence” for more information about relationships among us, our general partner and Diamondback.

Compensation Policies and Practices as They Relate to Risk Management

We do not have any employees. We are managed and operated by the directors and officers of our general partner and employees of Diamondback perform services on our behalf. Please read “–Compensation Discussion and Analysis” and “Items 1 and 2. Business and Properties–Our Relationship with Diamondback” for more information about this arrangement. For an analysis of any risks arising from Diamondback’s compensation policies and practices, please read Diamondback’s 2019 proxy statement. We have made awards of unit options subject to time-based vesting under our LTIP, which we believe drive a long-term perspective and which we believe make it less likely that executive officers will take unreasonable risks because the unit options retain value even in a depressed market.

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ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table presents information regarding the beneficial ownership of our common units as of January 25, 2019 by:

• our general partner;

• each of our general partner’s directors and executive officers;

• each unitholder known by us to beneficially hold 5% or more of our common units; and

• all of our general partner’s directors and executive officers as a group.

Name of Beneficial Owner	Common Units Beneficially Owned(1)	Percentage of Common Units Beneficially Owned
Diamondback Energy, Inc.(2)	731,500	1%
Viper Energy Partners GP LLC	—	—
Travis D. Stice(3)	100,333	*
Kaes Van't Hof(4)	29,537	*
Teresa L. Dick	11,540	*
Russell Pantermuehl	48,487	*
Thomas F. Hawkins	—	—
Randall J. Holder	14,622	*
Paul S. Molnar	18,487	*
Steven E. West (5)	56,487	—
W. Wesley Perry (5)	42,442	*
Spencer D. Armour(5)	6,414	*
Michael L. Hollis (6)	81,461	*
James L. Rubin (7)	—	—
Rosalind Redfern Grover (5)	16,776	*
All directors and executive officers as a group (13 persons)	426,586	*

* Less than 1%

(1) Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, (i) common units subject to options held by that person that are exercisable as of January 25, 2019 and (ii) common units subject to options or phantom units held by that person that are exercisable or vesting within 60 days of January 25, 2019 are all deemed to be beneficially owned. These common units, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of common units beneficially owned is based on 51,653,956 common units outstanding as of January 25, 2019. Unless otherwise indicated, all amounts exclude common units issuable upon the exercise of outstanding options and vesting of phantom units that are not exercisable and/or vested as of January 25, 2019 or within 60 days of January 25, 2019. Unless otherwise noted, the address for each beneficial owner listed below is 500 West Texas Avenue, Suite 1200, Midland, Texas 79701.

(2) Diamondback Energy, Inc. is a publicly traded company. The directors of Diamondback are Travis D. Stice, Steven E. West, Michael P. Cross, David L. Houston, Mark L. Plaumann, and Melanie M. Trent.

(3) All of these units are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Includes 16,011 phantom units, which will vest on February 16, 2019. Excludes 16,011 phantom units, which will vest on February 16, 2020.

(4) Includes 23,136 phantom units, which will vest on February 16, 2019. Excludes 23,136 phantom units, which will vest on February 16, 2020.

(5) Excludes 3,063 unvested phantom units that will vest on July 10, 2019.

(6) All of the units or options, as applicable, are held by MBH Investments, Ltd., which is managed by MBH Financial, LLC, its general partner. Mr. Hollis, his spouse and the Hollis 2014 Irrevocable Trust hold 100% of the membership interests in MBH Financial, LLC, of which Mr. Hollis is the manager.

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(7) Excludes 23,442 common units (representing vested phantom units previously granted to Mr. Rubin) and 3,063 unvested phantom units that will vest on July 10, 2019, all of which have been assigned by Mr. Rubin to Wexford under the terms of his employment with Wexford.

The following table sets forth, as of January 25, 2019, the number of shares of common stock of Diamondback beneficially owned by each of the directors and executive officers of our general partner and all directors and executive officers of our general partner as a group.

	Shares of Diamondback Common Stock Beneficially Owned(1)
Name of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percentage of Class
Travis D. Stice(2)	304,124	*
Kaes Van't Hof(3)	4,424	*
Teresa L. Dick(4)	24,781	*
Russell Pantermuehl(5)	85,088	*
Thomas F. Hawkins(6)	5,805	*
Randall J. Holder(7)	8,816	*
Paul S. Molnar(8)	35,356	*
Steven E. West(9)	5,887	*
W. Wesley Perry	—	—
Spencer D. Armour	—	—
Michael L. Hollis(10)	91,277	*
James L. Rubin	—	—
Rosalind Redfern Grover	—	—
All directors and executive officers as a group (13 persons)	565,558	*

* Less than 1%

(1) Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, (i) shares of common stock subject to options held by that person that are exercisable as of January 25, 2019 and (ii) shares of common stock subject to options or restricted stock units held by that person that are exercisable or vesting within 60 days of January 25, 2019, are all deemed to be beneficially owned. These shares, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of shares beneficially owned is based on 164,274,015 shares of common stock outstanding as of January 25, 2019. Unless otherwise indicated, all amounts exclude shares issuable upon the exercise of outstanding options and vesting of restricted stock units that are not exercisable and/or vested as of January 25, 2019 or within 60 days of January 25, 2019.

(2) All of these shares are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Includes (i) 7,410 restricted stock units, which will vest on February 16, 2019 and (ii) 6,797 restricted stock units, which will vest on February 21, 2019. Excludes 6,797 restricted stock units, which will vest on February 21, 2020. Also excludes (i) 22,230 performance-based restricted stock units awarded to Mr. Stice on February 16, 2017, which vested on December 31, 2018 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2018 by Diamondback’s compensation committee, and (ii) 22,230 performance-based restricted stock units awarded to Mr. Stice on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2019. Also excludes 30,585 performance-based restricted stock units awarded to Mr. Stice on February 13, 2018, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2020.

(3) Includes (i) 1,300 restricted stock units, which will vest on February 16, 2019 and (ii) 1,333 restricted stock units, which will vest on February 21, 2019. Excludes 1,333 restricted stock units, which will vest on February 21, 2020. Also excludes (i) 3,900 performance-based restricted stock units awarded to Mr. Van’t Hof on February 16, 2017, which vested on December 31, 2018 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2018 by Diamondback’s compensation committee, and (ii) 3,900 performance-based restricted stock units awarded to Mr. Van’t Hof on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2019. Also excludes 5,997 performance-based restricted stock units awarded to Mr. Van’t Hof on February 13,

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2018, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2020.

(4) Includes (i) 1,950 restricted stock units, which will vest on February 16, 2019 and (ii) 1,866 restricted stock units, which will vest on February 21, 2019. Excludes 1,866 restricted stock units, which will vest on February 21, 2020. Also excludes (i) 5,850 performance-based restricted stock units awarded to Ms. Dick on February 16, 2017, which vested on December 31, 2018 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2018 by Diamondback’s compensation committee, and (ii) 5,850 performance-based restricted stock units awarded to Ms. Dick on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2019. Also excludes 8,396 performance-based restricted stock units awarded to Ms. Dick on February 13, 2018, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2020.

(5) Includes (i) 3,900 restricted stock units, which will vest on February 16, 2019 and (ii) 3,412 restricted stock units, which will vest on February 21, 2019. Excludes 3,412 restricted stock units, which will vest on February 21, 2020. Also excludes (i) 11,700 performance-based restricted stock units awarded to Mr. Pantermuehl on February 16, 2017, which vested on December 31, 2018 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2018 by Diamondback’s compensation committee, and (ii) 11,700 performance-based restricted stock units awarded to Mr. Pantermuehl on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2019. Also excludes 15,353 performance-based restricted stock units awarded to Mr. Pantermuehl on February 13, 2018, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2020.

(6) Includes (i) 1,950 restricted stock units, which will vest on February 16, 2019 and (ii) 1,280 restricted stock units, which will vest on February 21, 2019. Excludes 1,280 restricted stock units, which will vest on February 21, 2020. Also excludes (i) 3,898 performance-based restricted stock units awarded to Mr. Hawkins on February 16, 2017, which vested on December 31, 2018 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2018 by Diamondback’s compensation committee, and (ii) 3,900 performance-based restricted stock units awarded to Mr. Hawkins on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2019. Also excludes 5,757 performance-based restricted stock units awarded to Mr. Hawkins on February 13, 2018, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2020.

(7) Includes (i) 1,950 restricted stock units, which will vest on February 16, 2019 and (ii) 1,866 restricted stock units, which will vest on February 21, 2019. Excludes 1,866 restricted stock units, which will vest on February 21, 2020. Also excludes (i) 5,850 performance-based restricted stock units awarded to Mr. Holder on February 16, 2017, which vested on December 31, 2018 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2018 by Diamondback’s compensation committee, and (ii) 5,850 performance-based restricted stock units awarded to Mr. Holder on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2019. Also excludes 8,396 performance-based restricted stock units awarded to Mr. Holder on February 13, 2018, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2020.

(8) Includes (i) 3,900 restricted stock units, which will vest on February 16, 2019 and (ii) 3,199 restricted stock units, which will vest on February 21, 2019. Excludes 3,199 restricted stock units, which will vest on February 21, 2020. Also excludes 11,700 performance-based restricted stock units awarded to Mr. Molnar on February 16, 2017, which vested on December 31, 2018 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance period ended on December 31, 2018 by Diamondback’s compensation committee, and (ii) 11,700 performance-based restricted stock units awarded to Mr. Molnar on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2019. Also excludes 14,393 performance-based restricted stock units awarded to Mr. Molnar on February 13, 2018, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2020.

(9) Excludes 1,574 shares of Diamondback common stock, which will vest on the earlier of the one-year anniversary of the date of grant and the date of the 2019 annual meeting of stockholders of Diamondback.

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(10) All of these shares are held by MBH Investments, Ltd., which is managed by MBH Financial, LLC, its general partner. Mr. Hollis, his spouse and the Hollis 2014 Irrevocable Trust hold 100% of the membership interests in MBH Financial, LLC, of which Mr. Hollis is the manager. Includes (i) 4,550 restricted stock units, which will vest on February 16, 2019 and (ii) 3,945 restricted stock units, which will vest on February 21, 2019. Excludes 3,945 restricted stock units, which will vest on February 21, 2020. Also excludes (i) 13,650 performance-based restricted stock units awarded to Mr. Hollis on February 16, 2017, which vested on December 31, 2018 (representing 200% vesting of the originally reported amount) subject to final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the two-year performance periods ending on December 31, 2018 by Diamondback’s compensation committee, and (ii) 13,650 performance-based restricted stock units awarded to Mr. Hollis on February 16, 2017, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2019. Also excludes 17,751 performance-based restricted stock units awarded to Mr. Hollis on February 13, 2018, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2020.

Securities Authorized For Issuance Under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of December 31, 2018:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans not approved by security holders(1)
Long Term Incentive Plan	125,053	$	—	8,842,492

(1) Our general partner adopted the LTIP in connection with the IPO in June 2014.

Changes in Control

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.

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Agreements and Transactions with Affiliates

We have entered into certain agreements and transactions with Diamondback and its affiliates, as described in more detail below.

Payments to our General Partner and its Affiliates

Under the terms of our partnership agreement, we are required to reimburse the 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 the general partner in connection with operating our business. The partnership agreement does not set a limit on the amount of expenses for which the 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. For the year ended December 31, 2018, the General Partner received $2.5 million in reimbursements from the Partnership.

Recapitalization, Tax Status Election and Related Transactions

In March 2018, we announced that the board of directors of our general partner unanimously approved a change of 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

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connection with making the Tax Election, on May 9, 2018 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 the 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, which we refer to as the exchange agreement. 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. Upon completion of our July 2018 offering of common units, we owned approximately 41% of the outstanding units issued by the Operating Company and Diamondback owned the remaining approximately 59%. 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 is anticipated to provide significant benefits to our business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. The foregoing transactions, other than the Tax Election, are being referred to herein as the recapitalization transaction.

Distributions paid to Diamondback

Following the recapitalization transaction, Diamondback is entitled to receive its pro rata portion of the distributions we make on our common units and the Operating Company makes in respect of the OpCo units. Holders of Class B units are not entitled to receive cash distributions except to the extent of the cash preferred distributions equal to 8% per annum payable quarterly on the $1.0 million capital contribution made to us by Diamondback pursuant to the recapitalization agreement in connection with the issuance of the Class B units in the recapitalization transaction. During the year ended December 31, 2018, Diamondback received distributions from us and the Operating Company in the aggregate amount of $155.1 million.

Registration Rights Agreement

On June 23, 2014, in connection with the IPO, we entered into a registration rights agreement with Diamondback. Pursuant to the registration rights agreement, we filed a registration statement on Form S-3 registering, under the Securities Act, the common units issued to Diamondback for resale. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates and, in certain circumstances, to third parties.

Simultaneously with the closing of the recapitalization transaction discussed above, Viper and Diamondback entered into an amended and restated registration rights agreement, dated as of May 9, 2018, which amended and restated the registration rights agreement with Diamondback, entered into on June 23, 2014 in connection with our IPO. The amended and restated registration rights agreement amended the definition of “registrable securities” to include common units acquired or that may be acquired by Diamondback in accordance with the exchange agreement. In addition, whenever a holder has requested that any registrable securities be registered under the amended and restated registration rights agreement or has initiated an underwritten offering, the amended and restated registration rights agreement requires such holder, if applicable, to cause such registrable securities to be exchanged into common units in accordance with the terms of the exchange agreement before or substantially concurrently with the sale of such registrable securities.

In July 2018, we filed a registration statement on Form S-3ASR pursuant to which, among other things, in accordance with the amended and restated registration rights agreement, we registered for resale by Diamondback (i) common units issuable to Diamondback upon exercise by Diamondback of its exchange right pursuant to the exchange agreement and Diamondback’s

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tender to us of an equivalent number of our outstanding Class B units and outstanding OpCo Units, in each case then held by Diamondback and (ii) common units then held by Diamondback.

Advisory Services Agreement

In connection with the closing of the IPO, we and the General Partner entered into an advisory services agreement with Wexford dated June 23, 2014, under which Wexford provided us and our general partner with general financial and strategic advisory services related to our business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. This agreement was terminated on November 12, 2018 with an effective date of December 31, 2018. For the year ended December 31, 2018, we did not pay any amounts under the advisory services agreement.

Tax Sharing Agreement

In connection with the closing of the IPO, we entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which we agreed to reimburse Diamondback for our share of state and local income and other taxes for which our results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax that we would have paid had we not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. In such a situation, we agreed to reimburse Diamondback for the tax we would have owed had the tax attributes not been available or used for our benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2018, we accrued state income tax expense of $0.2 million for our share of Texas margin tax for which our results are included in a combined tax return filed by Diamondback.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

The board of directors of our general partner has adopted policies for the review, approval and ratification of transactions with related persons. The board has adopted a written code of business conduct and ethics, under which a director is expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Any executive officer is required to avoid conflicts of interest unless approved by the board of directors of our general partner.

The code of business conduct and ethics described above was adopted in connection with the closing of the IPO, and as a result, the transactions described above were not reviewed according to such procedures.

Director Independence

The information required by Item 407(a) of Regulation S-K is included in “Item 10. Directors, Executive Officers and Corporate Governance” above.

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ITEM 14.     PRINCIPAL ACCOUNTING FEES AND SERVICES

The audit committee of the board of directors of our general partner selected Grant Thornton LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the years ended December 31, 2018, 2017 and 2016. The audit committee’s charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to our annual reports for the years ended December 31, 2018, 2017 and 2016 were approved by the audit committee.

The following table summarizes the aggregate Grant Thornton LLP fees that were allocated to us for independent auditing, tax and related services:

	Year Ended December 31,
	2018		2017		2016
	(in thousands)
Audit fees(1)	$	230	$	138	$	116
Audit-related fees(2)	—		—		—
Tax fees(3)	—		—		—
All other fees(4)	—		—		—
Total	$	230	$	138	$	116

(1) Audit fees represent amounts billed for each of the periods presented for professional services rendered in connection with those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters.

(2) Audit-related fees represent amounts billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews.

(3) Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning.

(4) All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above.

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PART IV

ITEM 15.     EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	Documents included in this report:
	1. Financial Statements
	Report of Independent Registered Public Accounting Firm	F-1
	Consolidated Balance Sheets	F-2
	Consolidated Statements of Operations	F-3
	Consolidated Statement of Unitholders’ Equity	F-4
	Consolidated Statements of Cash Flows	F-5
	Notes to Consolidated Financial Statements	F-6
	2. Financial Statement Schedules
	Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Partnership’s consolidated financial statements and related notes.

3. Exhibits
Exhibit Number	Description
2.1#	Purchase Agreement, dated as of November 21, 2017, among Viper Energy Partners LLC, DGK ORRI Company, L.P., as seller, and Royalty Resources L.P., as seller’s parent guarantor.
3.1	Certificate of Limited Partnership of Viper Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-195769) filed on May 7, 2014).
3.2	First Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
3.3	First Amendment to Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 10, 2018. (incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.4	Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 9, 2018, as amended as of May 10, 2018 (incorporated by reference to 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
4.1	Amended and Restated Registration Rights Agreement, dated as of May 9, 2018, by and between Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
10.1	Amended and Restated Credit Agreement, dated as of July 20, 2018, by and among, Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on July 26, 2018).
10.2	Contribution Agreement, dated June 17, 2014, by and among Viper Energy Partners LLC, Viper Energy Partners GP LLC, Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
10.3+	Viper Energy Partners LP Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
10.4	Advisory Services Agreement, dated June 23, 2014, by and among Viper Energy Partners LP, Viper Energy Partners GP LLC and Wexford Capital LP (incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
10.5	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
10.6	Tax Sharing Agreement, dated June 23, 2014, by and between Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.5 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).

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3. Exhibits
Exhibit Number	Description
10.7+	Form of Unit Option Agreement (incorporated by reference to Exhibit 10.6 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014).
10.8+	Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.2 of the Partnership’s Quarterly Report on Form 10-Q (File No. 001-36505) filed on November 6, 2014).
10.9	Recapitalization Agreement, dated as of March 28, 2018, by and among Diamondback Energy, Inc., Viper Energy Partners LLC, Viper Energy Partners GP LLC and Viper Energy Partners LP (incorporated by reference to Annex C to the Partnership’s Definitive Information Statement on Schedule 14C (File No. 001-36505) filed on April 17, 2018).
10.10	First Amendment to Recapitalization Agreement dated as of May 9, 2018, by and among Diamondback Energy, Inc., Viper Energy Partners LLC, Viper Energy Partners GP LLC and Viper Energy Partners LP. (incorporated by reference to Exhibit 10.4 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
10.11	Exchange Agreement, dated as of May 9, 2018, by and among Diamondback Energy, Inc., Viper Energy Partners LLC, Viper Energy Partners GP LLC and Viper Energy Partners LP. (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
10.12	First Amendment to Exchange Agreement, dated as of May 10, 2018, by and among Diamondback Energy, Inc., Viper Energy Partners LLC, Viper Energy Partners GP LLC and Viper Energy Partners LP. (incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
21.1*	List of Subsidiaries of Viper Energy Partners LP.
23.1*	Consent of Grant Thornton LLP.
23.2*	Consent of Ryder Scott Company, LP.
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1++	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
99.1*	Reserve Report of Ryder Scott Company, L.P.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

*	Filed herewith.
#	The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission.
+	Management contract, compensatory plan or arrangement.
++	The certifications attached as Exhibit 32.1 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this Annual Report to be signed on its behalf by the undersigned thereunto duly authorized.

		VIPER ENERGY PARTNERS LP
Date:	February 15, 2019
		By:	VIPER ENERGY PARTNERS GP LLC
			its general partner
		By:	/s/ Travis D. Stice
		Name:	Travis D. Stice
		Title:	Chief Executive Officer

Pursuant to the requirements of the Securities and Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Travis D. Stice	Chief Executive Officer and Director	February 15, 2019
Travis D. Stice	(Principal Executive Officer)
/s/ Teresa L. Dick	Chief Financial Officer	February 15, 2019
Teresa L. Dick	(Principal Financial and Accounting Officer)
/s/ Steven E. West	Director	February 15, 2019
Steven E. West
/s/ W. Wesley Perry	Director	February 15, 2019
W. Wesley Perry
/s/ Spencer D. Armour	Director	February 15, 2019
Spencer D. Armour
/s/ Michael L. Hollis	Director	February 15, 2019
Michael L. Hollis
/s/ James L. Rubin	Director	February 15, 2019
James L. Rubin
/s/ Rosalind Redfern Grover	Director	February 15, 2019
Rosalind Redfern Grover

S-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners

Viper Energy Partners LP

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Viper Energy Partners LP (a Delaware limited partnership) and subsidiary (collectively, the “Partnership”) as of December 31, 2018 and 2017, the related consolidated statements of operations, unitholders’ equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 15, 2019expressed an unqualified opinion.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2013.

Oklahoma City, Oklahoma

February 15, 2019

F-1

Viper Energy Partners LP

Consolidated Balance Sheets

	December 31,
	2018			2017
	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	22,676		$	24,197
Royalty income receivable	38,823			25,754
Royalty income receivable—related party	3,489			5,142
Other current assets	257			355
Total current assets	65,245			55,448
Property:
Oil and natural gas interests, full cost method of accounting ($871,485 and $514,724 excluded from depletion at December 31, 2018 and 2017, respectively)	1,716,713			1,103,897
Land	5,688			—
Accumulated depletion and impairment	(248,296		)	(189,466		)
Property, net	1,474,105			914,431
Funds held in escrow	—			6,304
Other assets	17,831			36,854
Deferred tax asset	96,883			—
Total assets	$	1,654,064		$	1,013,037
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	—		$	2,960
Other accrued liabilities	6,022			2,669
Total current liabilities	6,022			5,629
Long-term debt	411,000			93,500
Total liabilities	417,022			99,129
Commitments and contingencies (Note 11)
Unitholders’ equity:
General partner	1,000			—
Common units (51,653,956 units issued and outstanding as of December 31, 2018 and 113,882,045 units issued and outstanding as of December 31, 2017)	540,112			913,908
Class B units (72,418,500 units issued and outstanding as of December 31, 2018 and 0 units issued and outstanding as of December 31, 2017)	990			—
Total Viper Energy Partners LP unitholders’ equity	542,102			913,908
Non-controlling interest	694,940			—
Total equity	1,237,042			913,908
Total liabilities and unitholders’ equity	$	1,654,064		$	1,013,037

See accompanying notes to consolidated financial statements.

F-2

Viper Energy Partners LP

Consolidated Statements of Operations

	Year Ended December 31,
	2018			2017			2016
	(In thousands, except per unit amounts)
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	)
Net income (loss) attributable to common limited partners per unit:
Basic	$	2.01		$	1.07		$	(0.13	)
Diluted	$	2.01		$	1.07		$	(0.13	)
Weighted average number of common limited partner units outstanding:
Basic	71,546			104,318			83,081
Diluted	71,626			104,383			83,081

See accompanying notes to consolidated financial statements.

F-3

Viper Energy Partners LP

Statement of Consolidated Unitholders’ Equity

	Limited Partners										General Partner		Non-Controlling Interest
	Common					Class B					Amount		Amount
	Units		Amount			Units		Amount								Total
			(In thousands)
Balance at December 31, 2015	79,726		$	495,144		—		$	—		$	—	$	—		$	495,144
Net proceeds from the issuance of common units - public	6,050		93,462					—			—		—			93,462
Net proceeds from the issuance of common units - Diamondback	2,000		31,200					—			—		—			31,200
Unit-based compensation	24		3,815					—			—		—			3,815
Distributions to public			(9,574		)			—			—		—			(9,574		)
Distributions to Diamondback			(55,250		)			—			—		—			(55,250		)
Net loss			(10,899		)			—			—		—			(10,899		)
Balance at December 31, 2016	87,800		$	547,898		—		$	—		$	—	$	—		$	547,898
Net proceeds from the issuance of common units - public	25,175		369,896					—			—		—			369,896
Net proceeds from the issuance of common units - Diamondback	700		10,067					—			—		—			10,067
Common units issued for acquisition	175		3,050								—		—			3,050
Unit-based compensation	32		2,395					—			—		—			2,395
Distributions to public			(41,367		)			—			—		—			(41,367		)
Distributions to Diamondback			(89,509		)			—			—		—			(89,509		)
Net income			111,478					—			—		—			111,478
Balance at December 31, 2017	113,882		$	913,908		—		$	—		$	—	$	—		$	913,908
Impact of adoption of ASU 2016-01 (Note 2)			(18,651		)			—			—		—			(18,651		)
Unit exchange related to tax conversion	(73,150	)	(545,441		)	73,150		1,000			1,000		545,441			2,000
Recapitalization related to tax conversion	732		—			(732	)	(10		)	—		—			(10		)
Net proceeds from the issuance of common units - public	10,080		303,121					—			—		—			303,121
Unit-based compensation	103		2,763					—			—		—			2,763
Unit options exercised	8		140					—			—		—			140
Distributions to public			(98,333		)			—			—		—			(98,333		)
Distributions to Diamondback			(69,655		)			—			—		(85,454		)	(155,109		)
Distributions to General Partner			(31		)			—			—		—			(31		)
Change in ownership of consolidated subsidiaries, net			(91,667		)			—			—		116,034			24,367
Net income			143,958					—			—		118,919			262,877
Balance at December 31, 2018	51,654		$	540,112		72,419		$	990		$	1,000	$	694,940		$	1,237,042

See accompanying notes to consolidated financial statements.

F-4

Viper Energy Partners LP

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2018			2017			2016
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	262,877		$	111,478		$	(10,899	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Benefit from deferred income taxes	(72,516		)	—			—
Depletion	58,830			40,519			29,820
Loss on revaluation of investment	550			—			—
Impairment	—			—			47,469
Amortization of debt issuance costs	737			589			401
Non-cash unit-based compensation	2,763			2,395			3,815
Changes in operating assets and liabilities:
Restricted cash	—			500			—
Royalty income receivable	(13,069		)	(15,711		)	(4,144		)
Royalty income receivable—related party	1,653			(1,672		)	—
Accounts payable—related party	—			—			(4		)
Accounts payable and other accrued liabilities	2,545			1,298			1,945
Income tax payable	151			—			—
Other current assets	(28		)	(177		)	224
Net cash provided by operating activities	244,493			139,219			68,627
Cash flows from investing activities:
Acquisition of oil and natural gas interests	(610,131		)	(344,079		)	(205,721		)
Acquisition of land	(4,687		)	—			—
Proceeds from sale of assets	441			—			—
Proceeds from the sale of investments	124			—			—
Net cash used in investing activities	(614,253		)	(344,079		)	(205,721		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	691,500			278,500			164,000
Repayment on credit facility	(374,000		)	(305,500		)	(78,000		)
Debt issuance costs	(1,039		)	(2,259		)	(442		)
Proceeds from public offerings	305,773			380,412			125,580
Public offering costs	(2,652		)	(433		)	(546		)
Proceeds from exercise of unit options	140			—			—
Contributions by members	2,000			—			—
Distributions to partners	(253,483		)	(130,876		)	(64,824		)
Net cash provided by financing activities	368,239			219,844			145,768
Net increase (decrease) in cash	(1,521		)	14,984			8,674
Cash and cash equivalents at beginning of period	24,197			9,213			539
Cash and cash equivalents at end of period	$	22,676		$	24,197		$	9,213
Supplemental disclosure of cash flow information:
Interest paid	$	12,438		$	2,589		$	1,953

See accompanying notes to consolidated financial statements.

F-5

Viper Energy Partners LP

Notes to Financial Statements

1.    ORGANIZATION AND BASIS OF PRESENTATION

Organization

Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”), on February 27, 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. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of Viper Energy Partners LP and its consolidated subsidiary, Viper Energy Partners LLC.

As of December 31, 2018, a wholly-owned subsidiary of Diamondback, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback had an approximate 59% limited partner interest in the Partnership. Diamondback owns and controls the General Partner.

Recapitalization, Tax Status Election and Related Transactions

On May 9, 2018, we filed an election with the Internal Revenue Service to change the Partnership’s 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 the Partnership (i) amended and restated its 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 its existing registration rights agreement with Diamondback and (iv) entered into an exchange agreement with Diamondback, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback delivered and assigned to the Partnership the 73,150,000 common units Diamondback owned in exchange for (i) 73,150,000 of the Partnership’s 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, the Partnership 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 the Partnership’s 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 the Partnership’s 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 the Partnership in respect of its general partner interest and (ii) Diamondback made a cash capital contribution of $1.0 million to the Partnership 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 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and Diamondback continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s 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 the Partnership’s 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 the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

F-6

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

Basis of Presentation

The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities at the date of the financial statements.

The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, the recoverability of costs of unevaluated properties, unit–based compensation and estimate of income taxes.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments.

Restricted Cash

In 2014, the Predecessor entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The Predecessor subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matter in April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified as restricted cash.

Revenue from Contracts with Customers

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the operator. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

Royalty income from oil, natural gas and natural gas liquids sales

The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

F-7

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

Transaction price allocated to remaining performance obligations

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of our royalty income contracts.

Contract balances

Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year endedDecember 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, receivables, payables and a credit agreement. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments.

Oil and Natural Gas Properties

The Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2018 and 2017, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized 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. Depletion for oil and gas properties was $58.8 million, $40.5 million and $29.8 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not

F-8

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write-down is required. During the year ended December 31, 2016, the Partnership recorded an impairment on proved oil and natural gas properties of $47.5 million. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2018 and 2017.

Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property on an annual basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Debt Issuance Costs

Other assets include capitalized costs of $5.5 million, $4.4 million and $2.2 million, net of accumulated amortization of $2.2 million, $1.4 million and $0.8 million as of December 31, 2018, 2017 and 2016, respectively. The costs are associated with the Partnership’s credit agreement and are being amortized over the term of the credit agreement.

Royalty Interest and Revenue Recognition

Royalty interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when control passes to the producer.

Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur any of the costs of exploration, development and operation of the property.

Concentrations

The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2018, three purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (US) Company (“Shell Trading”) (31%), Concho Resources, Inc. (16%) and Trafigura Trading LLC (11%). For the year ended December 31, 2017, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (47%) and RSP Permian LLC (23%). For the year ended December 31, 2016, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (57%) and RSP Permian LLC (32%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Investments

The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. For the year endedDecember 31, 2018, the Partnership recorded a loss of $0.6 million, which then decreased the Partnership’s investment balance to $14.5 million, which is included in other assets in the accompanying consolidated balance sheets.

Earnings Per Unit

Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.

F-9

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

Unit–Based Compensation

Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 7—Unit–Based Compensation.

Income Taxes

The Partnership uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Partnership is subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 10—Income Taxes. In addition to the 2018 tax year, the Partnership’s 2015 through 2017 tax years, during which the Partnership was organized as a pass-through entity for federal income tax purposes, remain open to examination by tax authorities. As of December 31, 2018 and 2017, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2018, 2017 and 2016, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.

For the year endedDecember 31, 2018, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback. Diamondback does not expect any Texas margin tax to be due for the years ended December 31, 2017 and 2016, so no amount has been provided in the accompanying financial statements.

New Accounting Pronouncements

Recently Adopted Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Partnership adopted this standard effective January 1, 2018 using the modified retrospective method. The Partnership utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standard on its total revenues, operating income and the Partnership’s consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Partnership adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.

F-10

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of December 31, 2018, the Partnership was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. The Partnership adopted this standard effective January 1, 2019 using the modified retrospective method. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

F-11

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

3.    ACQUISITIONS

2018 Activity

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

On August 15, 2018, the Partnership 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.

2017 Activity

During the year ended December 31, 2017, the Partnership acquired mineral interests underlying 3,157 net royalty acres for an aggregate of approximately $343.1 million and, as of December 31, 2017, had mineral interests underlying 9,570 net royalty acres. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility, with a portion of the net proceeds from its January and July 2017 offerings of common units and with the issuance of 174,513 common units to a seller in a private placement in May 2017.

2016 Activity

During the year ended December 31, 2016, the Partnership acquired mineral interests underlying 2,142 net royalty acres in 63 transactions for an aggregate of approximately $205.7 million. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility and a portion of the net proceeds from its August 2016 offering of common units.

F-12

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

4.    OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:

	December 31,
	2018			2017
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	845,228		$	589,173
Not subject to depletion	871,485			514,724
Gross oil and natural gas interests	1,716,713			1,103,897
Accumulated depletion and impairment	(248,296		)	(189,466		)
Oil and natural gas interests, net	1,468,417			914,431
Land	5,688			—
Property, net of accumulated depletion and impairment	$	1,474,105		$	914,431
Balance of costs not subject to depletion:
Incurred in 2018	$	476,027
Incurred in 2017	284,371
Incurred in 2016	111,087
Total not subject to depletion	$	871,485

Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within three to five years.

Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas interests. Net capitalized costs are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Partnership’s oil and natural gas revenue, (b) the cost of interests not being amortized, if any, and (c) the lower of cost or market value of unproved interests included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write down is required.

As a result of the decline in prices, the Partnership recorded a non-cash impairment for the year ended December 31, 2016 of $47.5 million, which was included in accumulated depletion and impairment. There were no impairments recorded for the years ended December 31, 2018 and 2017. For 2016, the impairment charge affected the Partnership’s reported net loss but did not reduce its cash flow. In addition to commodity prices, the Partnership’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods.

5.    DEBT

Credit Agreement-Wells Fargo Bank

On July 8, 2014, the Partnership entered into a secured revolving credit agreement, as amended and restated (the “credit facility”), with Wells Fargo, as administrative agent, certain other lenders, and the Partnership’s consolidated subsidiary, Viper Energy Partners LLC (the “Operating Company”), as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and the Partnership became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, the Partnership, Wells Fargo and the other lenders amended and restated the credit agreement to reflect its assumption by the Operating Company. The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on its oil and natural gas reserves and other factors (the “borrowing base”) of $555.0 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The

F-13

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of December 31, 2018, the borrowing base was set at $555.0 million, and the Partnership had $411.0 million of outstanding borrowings and $144.0 million available for future borrowings under its revolving credit facility.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Operating Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus0.50% and 3-month LIBOR plus1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from0.75% to 1.75% per annum in the case of the alternative base rate and from1.75% to 2.75%per annum in the case of LIBOR, in each case depending on the amount of the loans outstanding in relation to the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all the assets of the Partnership and the Operating Company.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

As of December 31, 2018, the Operating Company was in compliance with all financial covenants under its credit agreement. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

6.    RELATED PARTY TRANSACTIONS

Acquisition

On August 15, 2018, the Partnership acquired from Diamondback mineral interests 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.

Partnership Agreement

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Partnership Agreement”), requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the 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 the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable

F-14

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

to the Partnership. For each of the years ended December 31, 2018 and 2017, the General Partner allocated $2.5 million, to the Partnership. For the year ended December 31, 2016, the General Partner did not allocate any amounts to the Partnership.

Advisory Services Agreement

In connection with the closing of the IPO, the Partnership and General Partner entered into an advisory services agreement with Wexford Capital LP (“Wexford”) dated as of June 23, 2014 (the “Advisory Services Agreement”), under which Wexford agreed to provide the Partnership and the General Partner with general financial and strategic advisory services related to the Partnership’s business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement was terminated on November 12, 2018 with an effective date of December 31, 2018. For the years ended December 31, 2018, 2017 and 2016, the Partnership did not pay any amounts under the Advisory Services Agreement.

Tax Sharing

In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback.

Lease Bonus

During the year ended December 31, 2018, Diamondback paid the Partnership $2.5 million in lease bonus payments to extend the term of 13 leases, reflecting an average bonus of $4,149 per acre and $0.6 million in lease bonus payments for one new lease, reflecting an average bonus of $18,002 per acre. During the year ended December 31, 2017, Diamondback paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre. During the year ended December 31, 2016, Diamondback paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.

7.    UNIT–BASED COMPENSATION

In connection with the IPO, the board of directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 8,967,545 common units has been reserved for issuance pursuant to the LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the board of directors of the General Partner or a committee thereof.

For the years ended December 31, 2018, 2017 and 2016, the Partnership incurred $2.8 million, $2.4 million and $3.8 million, respectively, of unit–based compensation.

Unit Options

In accordance with the LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the LTIP will consist of new common units of the Partnership. On June 17, 2014, the Partnership granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vested approximately 33% ratably on each of the first three anniversaries of the date of grant. All outstanding unit options were amended effective November 29, 2016 to provide that vested unit options would become exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning on the third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before and ending on the date a change of control occurs (the earlier

F-15

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

occurring of such events, the “Exercise Period”). At any time within the Exercise Period, if a participant attempted to exercise a vested unit option and the fair market value per unit as of such date was less than the exercise price per option unit, the vested unit option would not be exercisable. All of the unit options expired unexercised on December 31, 2017.

The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership.

	2014
Grant-date fair value	$	4.24
Expected volatility	36.0		%
Expected dividend yield	5.9		%
Expected term (in years)	3.0
Risk-free rate	0.99		%

The following table presents the unit option activity under the LTIP for the year ended December 31, 2018:

			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2017	7,600		$	18.49
Exercised	(7,600	)	$	18.49
Outstanding at December 31, 2018	—		$	—	0.00	$	—

The aggregate intrinsic value of unit options that were exercised during the year ended December 31, 2018 were $0.2 million.

Phantom Units

Under the LTIP, the board of directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient to one common unit of the Partnership for each phantom unit. The Partnership may also grant distribution equivalent rights with respect to Phantom Units. Distribution equivalent rights are rights to receive an amount equal to the cash distributions made during the period a phantom unit is outstanding.

The following table presents the phantom unit activity under the LTIP for the year ended December 31, 2018:

	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	105,439		$	17.10
Granted	127,402		$	25.54
Vested	(102,811	)	$	19.23
Forfeited	(4,977	)	$	29.71
Unvested at December 31, 2018	125,053		$	23.44

The aggregate fair value of phantom units that vested during the year ended December 31, 2018 was $2.0 million. As of December 31, 2018, the unrecognized compensation cost related to unvested phantom units was $1.6 million. Such cost is expected to be recognized over a weighted-average period of 0.98 years.

F-16

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

8.    UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and limited partner units. At December 31, 2018, the Partnership had a total of 51,653,956 common units and 72,418,500 Class B units issued and outstanding, of which 731,500 common units and 72,418,500 Class B units were owned by Diamondback, representing approximately 59% of the total Partnership’s units outstanding. The Operating Company units and the Partnership’s 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).

The following table summarizes changes in the number of the Partnership’s common units:

	Common Units
Balance at December 31, 2017	113,882,045
Common units issued in public offerings	10,080,000
Common units vested and issued under the LTIP	110,411
Unit exchange related to tax conversion	(73,150,000	)
Recapitalization related to tax conversion	731,500
Balance at December 31, 2018	51,653,956

The following table summarizes changes in the number of the Partnership’s Class B units:

	Class B Units
Balance at December 31, 2017	—
Unit exchange related to tax conversion	73,150,000
Recapitalization related to tax conversion	(731,500	)
Balance at December 31, 2018	72,418,500

In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which $120.5 million was used to repay the outstanding borrowings under the revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.

In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Diamondback purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of Diamondback and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowings under the revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes, which included additional acquisitions.

In July 2018, the Partnership 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 the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $303.1 million, after deducting underwriting discounts and commissions and offering expenses. The Partnership 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.

The board of directors of the General Partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis, beginning with the quarter ending September 30, 2014.

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Viper Energy Partners LP

Notes to Financial Statements - (Continued)

The following table presents cash distributions approved by the board of directors of the General Partner for the periods presented:

Declaration Date	Quarter	Amount per Common Unit		Payment Date	Amount Distributed to Diamondback
					(in thousands)
May 2, 2016	Q1 2016	$	0.149	May 23, 2016	$	10,497
July 21, 2016	Q2 2016	$	0.189	August 22, 2016	$	13,693
October 25, 2016	Q3 2016	$	0.207	November 18, 2016	$	14,997
February 3, 2017	Q4 2016	$	0.258	February 24, 2017	$	18,692
April 28, 2017	Q1 2017	$	0.302	May 25, 2017	$	21,880
July 28, 2017	Q2 2017	$	0.332	August 24, 2017	$	24,286
October 16, 2017	Q3 2017	$	0.337	November 14, 2017	$	24,652
January 31, 2018	Q4 2017	$	0.460	February 26, 2018	$	33,649
April 5, 2018	Q1 2018	$	0.480	April 27, 2018	$	35,112
July 27, 2018	Q2 2018	$	0.600	August 20, 2018	$	43,901
October 23, 2018	Q3 2018	$	0.580	November 19, 2018	$	42,447

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 the Partnership and the Operating Company for each quarter is determined by the board of directors of the Partnership’s 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 the Partnership’s general partner deems necessary or appropriate, if any, and the Partnership’s available cash will generally equal its Adjusted EBITDA (which will be the proportionate share of the available cash distributed to the Partnership by the Operating Company), less as a result of the Tax Election, cash needed for the payment of income taxes payable by the Partnership, if any.

9.    EARNINGS PER UNIT

The net income per common unit on the consolidated statements of operations is based on the net income (loss) of the Partnership for the years ended December 31, 2018, 2017 and 2016, since this is the amount of net income (loss) that is attributable to the Partnership’s common units.

The Partnership’s net income (loss) is allocated wholly to the common units. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 8—Unitholders’ Equity and Partnership Distributions.

Basic net income per common unit is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested common units granted under the LTIP.

F-18

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

	Year Ended December 31,
	2018		2017		2016
	(In thousands, except per unit amounts)
Net income (loss) attributable to the period	$	143,958	$	111,478	$	(10,899	)
Weighted average common units outstanding:
Basic weighted average common units outstanding	71,546		104,318		83,081
Effect of dilutive securities:
Potential common units issuable	80		65		—
Diluted weighted average common units outstanding	71,626		104,383		83,081
Net income (loss) per common unit, basic	$2.01		$1.07		$(0.13)
Net income (loss) per common unit, diluted	$2.01		$1.07		$(0.13)

The Partnership had the following units that were excluded from the computation of diluted earnings per unit because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per unit in future periods:

	Year Ended December 31,
	2018	2017	2016
	(in thousands)
Restricted stock units	1	40	1,567

10.    INCOME TAXES

As discussed further in Note 1, on March 29, 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. Because the operations of the business continue to be conducted through a pass-through entity, the Operating Company, in which the Partnership and Diamondback have ownership, represents a continuation of the historic pass-through entity for federal income tax purposes. Notwithstanding this federal income tax treatment, the change in the Partnership’s tax status is accounted for under financial accounting rules as a change in the Partnership’s tax status. This accounting treatment results in the Partnership’s financial statements reflecting a deferred tax benefit attributable to the Partnership succeeding to the tax basis of the Partnership’s unitholders in the unitholders’ Partnership units as of the effective date of the conversion.

Subsequent to the Partnership’s change in tax status, the Partnership provides for income taxes under the asset and liability method. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities, specifically the Partnership’s investment in the Operating Company, using enacted tax rates expected to be in effect during the year in which the basis differences reverse. Valuation allowances are established when Management determines it is more likely than not that some portion, or all, of the Partnership’s deferred tax assets will not be realized.

The Partnership’s effective income tax rate was (38.0)% for the year ended December 31, 2018. Total income tax benefit for the year ended December 31, 2018 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to (i) the impact of deferred taxes recognized as a result of the Partnership’s change in tax status, (ii) net income attributable to the non-controlling interest, and (iii) net income attributable to the period prior to the Partnership’s change in federal income tax status. For the year ended December 31, 2018, the Partnership recorded an income tax benefit of approximately $72.8 million related to deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s federal tax status and the Partnership’s succession to the partners’ tax bases in the Partnership at the date of the tax status change.

Prior to May 10, 2018, the effective date of the Partnership’s change in income tax status, the Partnership was treated as a pass-through entity for income tax purposes. As a result, the Partnership’s partners were responsible for federal income taxes on their share of the Partnership’s taxable income.

F-19

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

The components of the provision for income taxes for the year ended December 31, 2018 are as follows:

	Year Ended December 31, 2018
	(In thousands)
Current income tax provision (benefit):
Federal	$	—
State	151
Total current income tax provision	151
Deferred income tax provision (benefit):
Federal	(72,516		)
State	—
Total deferred income tax provision (benefit)	(72,516		)
Total provision for (benefit from) income taxes	$	(72,365	)

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:

	Year Ended December 31, 2018
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	40,008
Impact of net income attributable to the pre-incorporation period	(14,279		)
Impact of nontaxable noncontrolling interest	(24,973		)
State income tax expense (benefit), net of federal tax effect	119
Deferred taxes related to change in tax status	(72,787		)
Other, net	(453		)
Provision for (benefit from) income taxes	$	(72,365	)

F-20

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

The components of the Company’s deferred tax assets and liabilities as of December 31, 2018 are as follows:

	December 31, 2018
	(In thousands)
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$	2,131
Investment in the Operating Company	94,468
Other	284
Total deferred tax assets	96,883
Valuation allowance	—
Net deferred tax assets	96,883
Deferred tax liabilities:
Oil and natural gas properties and equipment	—
Other	—
Total deferred tax liabilities	—
Net deferred tax assets (liabilities)	$	96,883

As of December 31, 2018, the Partnership has net deferred tax assets of approximately $96.9 million, including $72.8 million recorded as a result of the Partnership’s change in tax status. Under federal income tax provisions applicable to the Partnership's change in tax status, the Partnership's basis for federal income tax purposes in its interest in the Operating Company consists primarily of the sum of the Partnership's unitholders' tax bases in their interests in the Partnership on the date of the tax status change. Under federal income tax reporting rules applicable to publicly traded partnerships ("PTPs"), partner information, including partner tax basis information, is required to be provided to the Partnership, but not in sufficient time for the Partnership to finalize its determination of the resultant tax basis in the Operating Company. The deferred tax asset reflected above represents the Partnership’s best estimate of the difference between its tax basis and its basis for financial accounting purposes in the Operating Company. The estimate is subject to revision, which the Partnership does not believe will be material, when the Partnership finalizes its federal income tax computations for 2018. The Partnership has federal net operating loss carryforwards of approximately $8.3 million which may be carried forward indefinitely to offset future taxable income.

Management considers the likelihood that the Partnership’s net operating losses and other deferred tax attributes will be utilized prior to their expiration. At December 31, 2018, Management’s assessment included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities and projected future taxable income. As a result of the assessment, Management determined that it is more likely than not that the Partnership will realize its deferred tax assets.

The Partnership principally operates in the state of Texas. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax attributable to the Partnership’s results which are included in a combined tax return filed by Diamondback. At December 31, 2018, the Partnership did not have any significant uncertain tax positions requiring recognition in the financial statements. In addition to the 2018 tax year, our 2015 through 2017 tax years, periods during which we were organized as a pass-through entity for income tax purposes, remain open to examination by tax authorities.

11.    COMMITMENTS AND CONTINGENCIES

The Partnership could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

F-21

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

12.    SUBSEQUENT EVENTS

Cash Distribution

On January 30, 2019, the board of directors of the General Partner approved a cash distribution 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.

13.    SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Partnership’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

	December 31,
	2018			2017
	(In thousands)
Oil and natural gas interests:
Proved	$	845,228		$	589,173
Unproved	871,485			514,724
Total oil and natural gas interests	1,716,713			1,103,897
Accumulated depletion and impairment	(248,296		)	(189,466		)
Net oil and natural gas interests capitalized	$	1,468,417		$	914,431

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

	December 31,
	2018		2017		2016
	(In thousands)
Acquisition costs:
Proved properties	$	256,055	$	55,948	$	31,441
Unproved properties	356,761		287,131		174,385
Total	$	612,816	$	343,079	$	205,826

F-22

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and natural gas liquids operations.

	December 31,
	2018			2017			2016
	(In thousands)
Royalty income	$	282,661		$	160,163		$	78,837
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		)
Income tax expense	(422		)	—			—
Results of operations from oil, natural gas and natural gas liquids	$	204,361		$	108,247		$	(4,411	)

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2018, 2017 and 2016 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

F-23

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

The changes in estimated proved reserves are as follows:

	Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)
	(In thousands)
Proved Developed and Undeveloped Reserves:
As of December 31, 2015	18,378		3,916		24,308
Purchase of reserves in place	1,138		437		2,315
Extensions and discoveries	5,647		1,477		7,181
Revisions of previous estimates	(2,041	)	74		(5,223	)
Production	(1,778	)	(328	)	(1,490	)
As of December 31, 2016	21,344		5,576		27,091
Purchase of reserves in place	2,106		252		5,245
Extensions and discoveries	7,859		1,813		11,106
Revisions of previous estimates	(2,525	)	(813	)	(3,498	)
Production	(2,899	)	(533	)	(3,549	)
As of December 31, 2017	25,885		6,295		36,395
Purchase of reserves in place	5,394		1,163		16,486
Extensions and discoveries	13,858		3,359		13,992
Revisions of previous estimates	1,140		1,108		564
Production	(4,399	)	(933	)	(5,840	)
As of December 31, 2018	41,878		10,992		61,597
Proved Developed Reserves:
December 31, 2016	12,332		3,247		15,933
December 31, 2017	18,788		4,536		29,256
December 31, 2018	29,526		7,965		49,681
Proved Undeveloped Reserves:
December 31, 2016	9,012		2,329		11,158
December 31, 2017	7,097		1,759		7,139
December 31, 2018	12,352		3,027		11,916

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2018, the Partnership’s extensions and discoveries of 19,549 MBoe resulted primarily from the drilling of 133 new wells and from 138 new proved undeveloped locations added. The Partnership’s positive revisions of previous estimated quantities of 2,342 MBoe were primarily due to changes in type curves and realized prices. The purchase of reserves in place of 9,305 MBoe were due to multiple acquisitions primarily located in Pecos, Reeves and Howard counties within the Permian Basin as well as an acquisition in the Eagle Ford Shale.

During the year ended December 31, 2017, the Partnership’s extensions and discoveries of 11,524 MBoe resulted primarily from the drilling of 96 new wells and from 40 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 3,921 MBoe were primarily due to changes in type curves. The purchase of reserves in place of 3,232 MBoe were due to multiple acquisitions with the largest being located in Pecos, Reeves and Loving counties.

During the year ended December 31, 2016, the Partnership’s extensions and discoveries of 7,125 MBoe resulted primarily from the drilling of 33 new wells and from 32 new proved undeveloped locations added. The Partnership’s negative revisions of

F-24

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

previous estimated quantities of 1,968 MBoe were primarily due to technical revisions with the remainder due to lower product pricing. The purchase of reserves in place of 1,575 MBoe were due to multiple acquisitions with the largest being located in Loving and Midland counties.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows are based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Partnership. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Partnership’s proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016:

	December 31,
	2018			2017			2016
	(In thousands)
Future cash inflows	$	2,962,386		$	1,445,883		$	948,090
Future production taxes	(200,079		)	(125,564		)	(69,109		)
Future income tax expense	(273,643		)	(6,932		)	(4,615		)
Future net cash flows	2,488,664			1,313,387			874,366
10% discount to reflect timing of cash flows	(1,349,282		)	(688,039		)	(461,785		)
Standardized measure of discounted future net cash flows	$	1,139,382		$	625,348		$	412,581

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows:

	December 31,
	2018		2017		2016
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	61.46	$	48.21	$	39.64
Natural gas (per Mcf)	$	1.84	$	2.13	$	1.36
Natural gas liquids (per Bbl)	$	25.04	$	19.15	$	11.69

F-25

Viper Energy Partners LP

Notes to Financial Statements - (Continued)

Principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership’s proved reserves are as follows:

	December 31,
	2018			2017			2016
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	625,348		$	412,581		$	395,763
Purchase of minerals in place	180,990			54,662			23,651
Sales of oil and natural gas, net of production costs	(266,055		)	(149,555		)	(74,628		)
Extensions and discoveries	423,540			214,479			104,451
Net changes in prices and production costs	187,592			99,382			(42,155		)
Revisions of previous quantity estimates	52,487			(50,773		)	(42,883		)
Net changes in income taxes	(123,804		)	(1,129		)	51
Accretion of discount	62,867			41,477			39,800
Net changes in timing of production and other	(3,583		)	4,224			8,531
Standardized measure of discounted future net cash flows at the end of the period	$	1,139,382		$	625,348		$	412,581

14.    QUARTERLY FINANCIAL DATA (Unaudited)

	2018
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
Operating income	$	62,443	$	75,406		$	78,603	$	72,368
Income from operations	43,703		54,926			54,846		49,512
Income tax expense (benefit)	—		(71,878		)	764		(1,251		)
Net income	42,896		128,464			50,812		40,705
Net income attributable to non-controlling interest	—		29,060			48,466		41,393
Net income (loss) attributable to Viper Energy Partners LP	$	42,896	$	99,404		$	2,346	$	(688	)
Net income (loss) attributable to common limited partners per unit:
Basic	$	0.38	$	1.36		$	0.05	$	(0.01	)
Diluted	$	0.38	$	1.35		$	0.05	$	(0.01	)

	2017
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
Operating income	$	33,652	$	36,622	$	42,533	$	59,226
Income from operations	21,450		22,479		27,067		42,825
Net income	$	20,652	$	22,149	$	26,607	$	42,070
Net income attributable to common limited partners per unit:
Basic	$	0.22	$	0.23	$	0.24	$	0.37
Diluted	$	0.22	$	0.23	$	0.24	$	0.37

F-26

EX-21.1

Exhibit 21.1

Viper Energy Partners LP

Subsidiaries of Registrant

Name of Subsidiary	Jurisdiction of Incorporation
Viper Energy Partners LLC	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated February 15, 2019, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of Viper Energy Partners LP on Form 10-K for the year ended December 31, 2018. We consent to the incorporation by reference of said report in the Registration Statements of Viper Energy Partners LP on Form S-3 ASR (File No. 333-226411, effective July 30, 2018) and Form S-8 (File No. 333-196971, effective June 23, 2014).

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

February 15, 2019

EX-23.2

Exhibit 23.2

CONSENT OF RYDER SCOTT COMPANY, L.P.

We have issued our report dated January 18, 2019 on estimates of proved reserves, future production and income attributable to certain royalty interests of Viper Energy Partners LP (“Viper”), a subsidiary of Diamondback Energy, Inc., as of December 31, 2018. As independent oil and gas consultants, we hereby consent to the inclusion of our report and the information contained therein and information from our prior reserve reports referenced in this Annual Report on Form 10-K of Viper (this “Annual Report”) and to all references to our firm in this Annual Report. We hereby also consent to the incorporation by reference of such reports and the information contained therein in the Registration Statements of Viper on Form S-8 (File No. 333-196971, effective June 23, 2014) and Form S-3 ASR (File No. 333-226411, effective July 30, 2018).

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 15, 2019

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Travis D. Stice, certify that:

1. I have reviewed this Annual Report on Form 10-K of Viper Energy Partners LP (the “registrant”).

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 15, 2019	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		Viper Energy Partners GP LLC
		(as general partner of Viper Energy Partners LP)

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Teresa L. Dick, certify that:

1. I have reviewed this Annual Report on Form 10-K of Viper Energy Partners LP (the “registrant”).

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 15, 2019	/s/ Teresa L. Dick
		Teresa L. Dick
		Chief Financial Officer
		Viper Energy Partners GP LLC
		(as general partner of Viper Energy Partners LP)

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PERIOD REPORT

In connection with the Annual Report on Form 10-K of Viper Energy Partners LP (the “Partnership”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Travis D. Stice, Chief Executive Officer of Viper Energy Partners GP LLC, the general partner of Viper Energy Partners LP, and Teresa L. Dick, Chief Financial Officer of Viper Energy Partners GP LLC, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to their knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date:	February 15, 2019	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		Viper Energy Partners GP LLC
		(as general partner of Viper Energy Partners LP)
Date:	February 15, 2019	/s/ Teresa L. Dick
		Teresa L. Dick
		Chief Financial Officer
		Viper Energy Partners GP LLC
		(as general partner of Viper Energy Partners LP)

EX-99.1

VIPER ENERGY PARTNERS, LP

Estimated

Future Reserves and Income

Attributable to Certain

Royalty Interests

SEC Parameters

As of

December 31, 2018

\s\ Val Rick Robinson

Val Rick Robinson, P.E.

TBPE License No. 105137

Managing Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Viper Energy Partners, LP

January 18, 2019

Page 1

January 18, 2019

Viper Energy Partners, LP

500 West Texas, Suite 1210

Midland, Texas 79701

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain royalty interests of Viper Energy Partners, LP (Viper), a subsidiary of Diamondback Energy, Inc. (Diamondback) as of December 31, 2018. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 2, 2019 and presented herein, was prepared for public disclosure by Viper in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Viper as of December 31, 2018.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2018 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

SUITE 800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

Viper Energy Partners, LP

January 18, 2019

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Royalty Interests of

Viper Energy Partners, LP

As of December 31, 2018

	Proved
	Developed				Total
	Producing		Undeveloped		Proved
Net Reserves
Oil/Condensate – Mbbl	29,526		12,352		41,878
Plant Products – Mbbl	7,965		3,027		10,992
Gas – MMcf	49,681		11,916		61,597
MBOE	45,771		17,365		63,136
Income Data ($M)
Future Gross Revenue		$2,005,348		$809,368		$2,814,716
Deductions	38,298		14,111		52,409
Future Net Income (FNI)		$1,967,050		$795,257		$2,762,307
Discounted FNI @ 10%	$	888,590		$377,914		$1,266,504

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software packageARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Diamondback. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate ad valorem taxes only. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 96 percent and gas reserves account for the remaining 4 percent of total future gross revenue from proved reserves.

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Viper Energy Partners, LP

January 18, 2019

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The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M)
	As of December 31, 2018
Discount Rate		Total
Percent		Proved
5		$1,696,282
15		$1,034,055
20		$885,987
30		$704,359

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined under the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Viper’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods.

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January 18, 2019

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The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Diamondback’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Viper owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

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 set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). 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 individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator.

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January 18, 2019

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Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. Approximately 90 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through December 2018 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Diamondback or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves were estimated by analogy, or a combination of methods. These methods were 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 reserves estimates was considered to be inappropriate.

All proved undeveloped reserves included herein were estimated by performance methods and/or analogy.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Diamondback has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Diamondback with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product

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prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Diamondback. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Diamondback. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

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Viper Energy Partners, LP

January 18, 2019

Page 7

Diamondback furnished us with the above mentioned average prices in effect on December 31, 2018. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Diamondback. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Diamondback to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$65.56/bbl	$61.46/bbl
United States	NGLs	WTI Cushing	$65.56/bbl	$25.04/bbl
	Gas	Henry Hub	$3.10/MMBTU	$1.84/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

As a holder of royalty interests only, Viper bears none of the operating or development costs associated with the underlying properties of this report. Nevertheless, the proved undeveloped reserves in this report have been incorporated herein in accordance with Diamondback’s plans to develop these reserves as of December 31, 2018. The implementation of Diamondback’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Diamondback’s management. As the result of our inquiries during the course of preparing this report, Diamondback has informed us that the development activities included herein have been subjected to and received the internal approvals required by Diamondback’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Diamondback. Where appropriate, Diamondback has provided written documentation supporting their commitment to proceed with the development activities as presented to

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January 18, 2019

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us. Additionally, Diamondback has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2018, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Diamondback were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Viper. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Viper.

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Viper Energy Partners, LP

January 18, 2019

Page 9

Viper makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Viper has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3of Viper, of the references to our name, as well as to the references to our third party report for Viper, which appears in the December 31, 2018 annual report on Form 10-Kof Viper. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Viper.

We have provided Viper with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filingsmade by Viper and the original signed report letter, the original signed report letter shall control and supersede the digital version.

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Viper Energy Partners, LP

January 18, 2019

Page 10

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Val Rick Robinson

Val Rick Robisnon, P.E.

TBPE License No. 105137

Managing Senior Vice President

[SEAL]

VRR (DPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Engineer

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Val Rick Robinson was the primary technical person responsible for the estimate of the reserves, future production and income presented herein.

Mr. Robinson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Robinson served in a number of engineering positions with ExxonMobil Corporation. For more information regarding Mr. Robinson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com.

Mr. Robinson earned a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Robinson fulfills. As part of his 2018 continuing education hours, Mr. Robinson attended 21 hours of formalized training including the 2018 RSC Reserves Conference and various professional society presentations covering such topics as the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, overviews of the various productive basins of North America, computer software, and professional ethics.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Robinson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

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Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): 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).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

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(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

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Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Jan. 31, 2019	Jun. 30, 2018	Dec. 31, 2017
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Entity Registrant Name	Viper Energy Partners LP
Entity Central Index Key	0001602065
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Units, Units Outstanding		51,653,956
Class B Units Outstanding	72,418,500	72,418,500		0
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,288,629,954

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 22,676	$ 24,197
Royalty income receivable	38,823	25,754
Royalty income receivable—related party	3,489	5,142
Other current assets	257	355
Total current assets	65,245	55,448
Property:
Oil and natural gas interests, full cost method of accounting ($871,485 and $514,724 excluded from depletion at December 31, 2018 and 2017, respectively)	1,716,713	1,103,897
Land	5,688	0
Accumulated depletion and impairment	(248,296)	(189,466)
Property, net	1,474,105	914,431
Funds held in escrow	0	6,304
Other assets	17,831	36,854
Deferred tax asset	96,883	0
Total assets	1,654,064	1,013,037
Current liabilities:
Accounts payable	0	2,960
Other accrued liabilities	6,022	2,669
Total current liabilities	6,022	5,629
Long-term debt	411,000	93,500
Total liabilities	417,022	99,129
Commitments and contingencies
Unitholders’ equity:
General partner	1,000	0
Common units (51,653,956 units issued and outstanding as of December 31, 2018 and 113,882,045 units issued and outstanding as of December 31, 2017)	540,112	913,908
Class B units (72,418,500 units issued and outstanding as of December 31, 2018 and 0 units issued and outstanding as of December 31, 2017)	990	0
Total Viper Energy Partners LP unitholders’ equity	542,102	913,908
Non-controlling interest	694,940	0
Total equity	1,237,042	913,908
Total liabilities and unitholders’ equity	$ 1,654,064	$ 1,013,037

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Oil and natural gas interests, based on the full cost method of accounting, amount excluded from depletion	$ 871,485	$ 514,724
Common units issued	51,653,956	113,882,045
Common units outstanding	51,653,956	113,882,045
Class B Units Issued	72,418,500	0
Class B Units Outstanding	72,418,500	0

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue	$ 288,820	$ 172,033	$ 79,146
Lease bonus income	2,920	11,764	0
Lease bonus income - related party	3,109	106	309
Other operating income	130	0	0
Costs and expenses:
Production and ad valorem taxes	19,048	10,608	5,544
Depletion	58,830	40,519	29,820
Impairment	0	0	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)	0	0
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)	0	0
Net income (loss)	262,877	111,478	(10,899)
Net income attributable to non-controlling interest	118,919	0	0
Net income (loss) attributable to Viper Energy Partners LP	$ 143,958	$ 111,478	$ (10,899)
Net income (loss) attributable to common limited partners per unit:
Basic (dollars per unit)	$ 2.01	$ 1.07	$ (0.13)
Diluted (dollars per unit)	$ 2.01	$ 1.07	$ (0.13)
Weighted average number of common limited partner units outstanding:
Basic (in units)	71,546	104,318	83,081
Diluted (in units)	71,626	104,383	83,081
Royalty [Member]
Revenue	$ 282,661	$ 160,163	$ 78,837
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Costs and expenses:
Gathering and transportation	$ 0	$ 789	$ 415

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Statement of Consolidated Unitholders' Equity and Members' Equity - USD ($) $ in Thousands	Total	General Partner [Member]	Non-Controlling Interest [Member]	Limited Partner, Diamondback [Member]	Common Class A [Member]	Common Class A [Member] Limited Partner [Member]	Common Class A [Member] Limited Partner, Diamondback [Member]	Capital Unit, Class B [Member]	Capital Unit, Class B [Member] Limited Partner [Member]
Partners' Capital including noncontrolling interest at Dec. 31, 2015	$ 495,144	$ 0	$ 0			$ 495,144			$ 0
Common Stock, Shares, Outstanding at Dec. 31, 2015						79,726,000
Class B Units Outstanding at Dec. 31, 2015									0
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued in public offering						6,050,000	2,000,000
Net proceeds from the issuance of common units	93,462	0	0	$ 31,200		$ 93,462	$ 31,200		$ 0
Unit-based compensation, units						24,000
Unit-based compensation	3,815	0	0			$ 3,815			0
Distribution to public	(9,574)	0	0			(9,574)			0
Distribution to Diamondback	(55,250)	0	0			(55,250)			0
Net income (loss)	(10,899)	0	0			$ (10,899)			$ 0
Common Stock, Shares, Outstanding at Dec. 31, 2016						87,800,000
Class B Units Outstanding at Dec. 31, 2016									0
Partners' Capital including noncontrolling interest at Dec. 31, 2016	547,898	0	0			$ 547,898			$ 0
Increase (Decrease) in Partners' Capital [Roll Forward]
Units issued in public offering						25,175,000	700,000
Net proceeds from the issuance of common units	369,896	0	0	$ 10,067		$ 369,896	$ 10,067		0
Common units issued for acquisition, units						175,000
Common units issued for acquisition	3,050	0	0			$ 3,050
Unit-based compensation, units						32,000
Unit-based compensation	2,395	0	0			$ 2,395			0
Distribution to public	(41,367)	0	0			(41,367)			0
Distribution to Diamondback	(89,509)	0	0			(89,509)			0
Net income (loss)	$ 111,478	0	0			$ 111,478			$ 0
Common Stock, Shares, Outstanding at Dec. 31, 2017						113,882,000
Class B Units Outstanding at Dec. 31, 2017	0								0
Partners' Capital including noncontrolling interest at Dec. 31, 2017	$ 913,908	0	0			$ 913,908			$ 0
Increase (Decrease) in Partners' Capital [Roll Forward]
Unit exchange related to tax conversion, units					(73,150,000)	(73,150,000)		73,150,000	73,150,000
Unit exchange related to tax conversion	2,000	1,000	545,441			$ (545,441)			$ 1,000
Recapitalization related to tax conversion, units					731,500	732,000		(731,500)	(732,000)
Recapitalization related to tax conversion	(10)	0	0			$ 0			$ (10)
Units issued in public offering						10,080,000
Net proceeds from the issuance of common units	$ 303,121	0	0			$ 303,121			0
Unit-based compensation, units	110,411					103,000
Unit-based compensation	$ 2,763	0	0			$ 2,763			0
Partner's Capital Account, Units, Exercised						8,000
Partners' Capital Account, Option Exercise	140	0	0			$ 140			0
Distribution to public	(98,333)	0	0			(98,333)			0
Distribution to Diamondback	(155,109)	0	(85,454)			(69,655)			0
Distributions to General Partner	(31)	0	0			(31)			0
Change in ownership of consolidated subsidiaries, net	24,367	0	116,034			(91,667)			0
Net income (loss)	$ 262,877	0	118,919			$ 143,958			$ 0
Common Stock, Shares, Outstanding at Dec. 31, 2018						51,654,000
Class B Units Outstanding at Dec. 31, 2018	72,418,500								72,419,000
Partners' Capital including noncontrolling interest at Dec. 31, 2018	$ 1,237,042	1,000	694,940			$ 540,112			$ 990
Increase (Decrease) in Partners' Capital [Roll Forward]
Impact of adoption of ASU 2016-01						$ (18,651)
Net income (loss)	$ 40,705
Common Stock, Shares, Outstanding at Dec. 31, 2018						51,654,000
Class B Units Outstanding at Dec. 31, 2018	72,418,500								72,419,000
Partners' Capital including noncontrolling interest at Dec. 31, 2018	$ 1,237,042	1,000	694,940			$ 540,112			$ 990
Increase (Decrease) in Partners' Capital [Roll Forward]
Impact of adoption of ASU 2016-01	$ (18,651)	$ 0	$ 0			$ (18,651)			$ 0

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 262,877	$ 111,478	$ (10,899)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Benefit from deferred income taxes	(72,516)	0	0
Depletion	58,830	40,519	29,820
Loss on revaluation of investment	550	0	0
Impairment	0	0	47,469
Amortization of debt issuance costs	737	589	401
Non-cash unit-based compensation	2,763	2,395	3,815
Changes in operating assets and liabilities:
Restricted cash	0	500	0
Royalty income receivable	(13,069)	(15,711)	(4,144)
Royalty income receivable—related party	1,653	(1,672)	0
Accounts payable—related party	0	0	(4)
Accounts payable and other accrued liabilities	2,545	1,298	1,945
Income tax payable	151	0	0
Other current assets	(28)	(177)	224
Net cash provided by operating activities	244,493	139,219	68,627
Cash flows from investing activities:
Acquisition of oil and natural gas interests	(610,131)	(344,079)	(205,721)
Acquisition of land	4,687	0	0
Proceeds from sale of assets	441	0	0
Proceeds from the sale of investments	124	0	0
Net cash used in investing activities	(614,253)	(344,079)	(205,721)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	691,500	278,500	164,000
Repayment on credit facility	(374,000)	(305,500)	(78,000)
Debt issuance costs	(1,039)	(2,259)	(442)
Proceeds from public offerings	305,773	380,412	125,580
Public offering costs	(2,652)	(433)	(546)
Proceeds from exercise of unit options	140	0	0
Contributions by members	2,000	0	0
Distributions to partners	(253,483)	(130,876)	(64,824)
Net cash provided by financing activities	368,239	219,844	145,768
Net increase (decrease) in cash	(1,521)	14,984	8,674
Cash and cash equivalents at beginning of period	24,197	9,213	539
Cash and cash equivalents at end of period	22,676	24,197	9,213
Supplemental disclosure of cash flow information:
Interest paid	$ 12,438	$ 2,589	$ 1,953

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Presentation

ORGANIZATION AND BASIS OF PRESENTATION

Organization

Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”), on February 27, 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. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of Viper Energy Partners LP and its consolidated subsidiary, Viper Energy Partners LLC.

As of December 31, 2018, a wholly-owned subsidiary of Diamondback, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback had an approximate 59% limited partner interest in the Partnership. Diamondback owns and controls the General Partner.

Recapitalization, Tax Status Election and Related Transactions

On May 9, 2018, we filed an election with the Internal Revenue Service to change the Partnership’s 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 the Partnership (i) amended and restated its 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 its existing registration rights agreement with Diamondback and (iv) entered into an exchange agreement with Diamondback, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback delivered and assigned to the Partnership the 73,150,000 common units Diamondback owned in exchange for (i) 73,150,000 of the Partnership’s 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, the Partnership 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 the Partnership’s 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 the Partnership’s 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 the Partnership in respect of its general partner interest and (ii) Diamondback made a cash capital contribution of $1.0 million to the Partnership 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 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and Diamondback continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s 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 the Partnership’s 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 the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Basis of Presentation

The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities at the date of the financial statements.

The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, the recoverability of costs of unevaluated properties, unit–based compensation and estimate of income taxes.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments.

Restricted Cash

In 2014, the Predecessor entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The Predecessor subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matter in April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified as restricted cash.

Revenue from Contracts with Customers

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the operator. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

Royalty income from oil, natural gas and natural gas liquids sales

The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

Transaction price allocated to remaining performance obligations

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of our royalty income contracts.

Contract balances

Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year endedDecember 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, receivables, payables and a credit agreement. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments.

Oil and Natural Gas Properties

The Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2018 and 2017, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized 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. Depletion for oil and gas properties was $58.8 million, $40.5 million and $29.8 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write-down is required. During the year ended December 31, 2016, the Partnership recorded an impairment on proved oil and natural gas properties of $47.5 million. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2018 and 2017.

Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property on an annual basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Debt Issuance Costs

Other assets include capitalized costs of $5.5 million, $4.4 million and $2.2 million, net of accumulated amortization of $2.2 million, $1.4 million and $0.8 million as of December 31, 2018, 2017 and 2016, respectively. The costs are associated with the Partnership’s credit agreement and are being amortized over the term of the credit agreement.

Royalty Interest and Revenue Recognition

Royalty interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when control passes to the producer.

Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur any of the costs of exploration, development and operation of the property.

Concentrations

The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2018, three purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (US) Company (“Shell Trading”) (31%), Concho Resources, Inc. (16%) and Trafigura Trading LLC (11%). For the year ended December 31, 2017, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (47%) and RSP Permian LLC (23%). For the year ended December 31, 2016, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (57%) and RSP Permian LLC (32%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Investments

The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. For the year endedDecember 31, 2018, the Partnership recorded a loss of $0.6 million, which then decreased the Partnership’s investment balance to $14.5 million, which is included in other assets in the accompanying consolidated balance sheets.

Earnings Per Unit

Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.

Unit–Based Compensation

Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 7—Unit–Based Compensation.

Income Taxes

The Partnership uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Partnership is subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 10—Income Taxes. In addition to the 2018 tax year, the Partnership’s 2015 through 2017 tax years, during which the Partnership was organized as a pass-through entity for federal income tax purposes, remain open to examination by tax authorities. As of December 31, 2018 and 2017, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2018, 2017 and 2016, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.

For the year endedDecember 31, 2018, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback. Diamondback does not expect any Texas margin tax to be due for the years ended December 31, 2017 and 2016, so no amount has been provided in the accompanying financial statements.

New Accounting Pronouncements

Recently Adopted Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Partnership adopted this standard effective January 1, 2018 using the modified retrospective method. The Partnership utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standard on its total revenues, operating income and the Partnership’s consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Partnership adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of December 31, 2018, the Partnership was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. The Partnership adopted this standard effective January 1, 2019 using the modified retrospective method. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

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Acquisitions

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Acquisitions

ACQUISITIONS

2018 Activity

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

On August 15, 2018, the Partnership 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.

2017 Activity

During the year ended December 31, 2017, the Partnership acquired mineral interests underlying 3,157 net royalty acres for an aggregate of approximately $343.1 million and, as of December 31, 2017, had mineral interests underlying 9,570 net royalty acres. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility, with a portion of the net proceeds from its January and July 2017 offerings of common units and with the issuance of 174,513 common units to a seller in a private placement in May 2017.

2016 Activity

During the year ended December 31, 2016, the Partnership acquired mineral interests underlying 2,142 net royalty acres in 63 transactions for an aggregate of approximately $205.7 million. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility and a portion of the net proceeds from its August 2016 offering of common units.

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Oil and Natural Gas Interests

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Oil and Natural Gas Interests

OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:

	December 31,
	2018			2017
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	845,228		$	589,173
Not subject to depletion	871,485			514,724
Gross oil and natural gas interests	1,716,713			1,103,897
Accumulated depletion and impairment	(248,296		)	(189,466		)
Oil and natural gas interests, net	1,468,417			914,431
Land	5,688			—
Property, net of accumulated depletion and impairment	$	1,474,105		$	914,431
Balance of costs not subject to depletion:
Incurred in 2018	$	476,027
Incurred in 2017	284,371
Incurred in 2016	111,087
Total not subject to depletion	$	871,485

Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within three to five years.

Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas interests. Net capitalized costs are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Partnership’s oil and natural gas revenue, (b) the cost of interests not being amortized, if any, and (c) the lower of cost or market value of unproved interests included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write down is required.

As a result of the decline in prices, the Partnership recorded a non-cash impairment for the year ended December 31, 2016 of $47.5 million, which was included in accumulated depletion and impairment. There were no impairments recorded for the years ended December 31, 2018 and 2017. For 2016, the impairment charge affected the Partnership’s reported net loss but did not reduce its cash flow. In addition to commodity prices, the Partnership’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods.

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Debt

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt

DEBT

Credit Agreement-Wells Fargo Bank

On July 8, 2014, the Partnership entered into a secured revolving credit agreement, as amended and restated (the “credit facility”), with Wells Fargo, as administrative agent, certain other lenders, and the Partnership’s consolidated subsidiary, Viper Energy Partners LLC (the “Operating Company”), as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and the Partnership became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, the Partnership, Wells Fargo and the other lenders amended and restated the credit agreement to reflect its assumption by the Operating Company. The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on its oil and natural gas reserves and other factors (the “borrowing base”) of $555.0 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of December 31, 2018, the borrowing base was set at $555.0 million, and the Partnership had $411.0 million of outstanding borrowings and $144.0 million available for future borrowings under its revolving credit facility.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Operating Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus0.50% and 3-month LIBOR plus1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from0.75% to 1.75% per annum in the case of the alternative base rate and from1.75% to 2.75%per annum in the case of LIBOR, in each case depending on the amount of the loans outstanding in relation to the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all the assets of the Partnership and the Operating Company.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

As of December 31, 2018, the Operating Company was in compliance with all financial covenants under its credit agreement. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

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Related Party Transactions

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Acquisition

On August 15, 2018, the Partnership acquired from Diamondback mineral interests 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.

Partnership Agreement

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Partnership Agreement”), requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the 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 the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For each of the years ended December 31, 2018 and 2017, the General Partner allocated $2.5 million, to the Partnership. For the year ended December 31, 2016, the General Partner did not allocate any amounts to the Partnership.

Advisory Services Agreement

In connection with the closing of the IPO, the Partnership and General Partner entered into an advisory services agreement with Wexford Capital LP (“Wexford”) dated as of June 23, 2014 (the “Advisory Services Agreement”), under which Wexford agreed to provide the Partnership and the General Partner with general financial and strategic advisory services related to the Partnership’s business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement was terminated on November 12, 2018 with an effective date of December 31, 2018. For the years ended December 31, 2018, 2017 and 2016, the Partnership did not pay any amounts under the Advisory Services Agreement.

Tax Sharing

In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback.

Lease Bonus

During the year ended December 31, 2018, Diamondback paid the Partnership $2.5 million in lease bonus payments to extend the term of 13 leases, reflecting an average bonus of $4,149 per acre and $0.6 million in lease bonus payments for one new lease, reflecting an average bonus of $18,002 per acre. During the year ended December 31, 2017, Diamondback paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre. During the year ended December 31, 2016, Diamondback paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.

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Unit-Based Compensation

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Unit-Based Compensation

UNIT–BASED COMPENSATION

In connection with the IPO, the board of directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 8,967,545 common units has been reserved for issuance pursuant to the LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the board of directors of the General Partner or a committee thereof.

For the years ended December 31, 2018, 2017 and 2016, the Partnership incurred $2.8 million, $2.4 million and $3.8 million, respectively, of unit–based compensation.

Unit Options

In accordance with the LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the LTIP will consist of new common units of the Partnership. On June 17, 2014, the Partnership granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vested approximately 33% ratably on each of the first three anniversaries of the date of grant. All outstanding unit options were amended effective November 29, 2016 to provide that vested unit options would become exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning on the third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before and ending on the date a change of control occurs (the earlier occurring of such events, the “Exercise Period”). At any time within the Exercise Period, if a participant attempted to exercise a vested unit option and the fair market value per unit as of such date was less than the exercise price per option unit, the vested unit option would not be exercisable. All of the unit options expired unexercised on December 31, 2017.

The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership.

	2014
Grant-date fair value	$	4.24
Expected volatility	36.0		%
Expected dividend yield	5.9		%
Expected term (in years)	3.0
Risk-free rate	0.99		%

The following table presents the unit option activity under the LTIP for the year ended December 31, 2018:

			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2017	7,600		$	18.49
Exercised	(7,600	)	$	18.49
Outstanding at December 31, 2018	—		$	—	0.00	$	—

The aggregate intrinsic value of unit options that were exercised during the year ended December 31, 2018 were $0.2 million.

Phantom Units

Under the LTIP, the board of directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient to one common unit of the Partnership for each phantom unit. The Partnership may also grant distribution equivalent rights with respect to Phantom Units. Distribution equivalent rights are rights to receive an amount equal to the cash distributions made during the period a phantom unit is outstanding.

The following table presents the phantom unit activity under the LTIP for the year ended December 31, 2018:

	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	105,439		$	17.10
Granted	127,402		$	25.54
Vested	(102,811	)	$	19.23
Forfeited	(4,977	)	$	29.71
Unvested at December 31, 2018	125,053		$	23.44

The aggregate fair value of phantom units that vested during the year ended December 31, 2018 was $2.0 million. As of December 31, 2018, the unrecognized compensation cost related to unvested phantom units was $1.6 million. Such cost is expected to be recognized over a weighted-average period of 0.98 years.

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Partners' Capital and Partnership Distributions

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Partners' Capital and Partnership Distributions

UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and limited partner units. At December 31, 2018, the Partnership had a total of 51,653,956 common units and 72,418,500 Class B units issued and outstanding, of which 731,500 common units and 72,418,500 Class B units were owned by Diamondback, representing approximately 59% of the total Partnership’s units outstanding. The Operating Company units and the Partnership’s 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).

The following table summarizes changes in the number of the Partnership’s common units:

	Common Units
Balance at December 31, 2017	113,882,045
Common units issued in public offerings	10,080,000
Common units vested and issued under the LTIP	110,411
Unit exchange related to tax conversion	(73,150,000	)
Recapitalization related to tax conversion	731,500
Balance at December 31, 2018	51,653,956

The following table summarizes changes in the number of the Partnership’s Class B units:

	Class B Units
Balance at December 31, 2017	—
Unit exchange related to tax conversion	73,150,000
Recapitalization related to tax conversion	(731,500	)
Balance at December 31, 2018	72,418,500

In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which $120.5 million was used to repay the outstanding borrowings under the revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.

In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Diamondback purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of Diamondback and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowings under the revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes, which included additional acquisitions.

In July 2018, the Partnership 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 the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $303.1 million, after deducting underwriting discounts and commissions and offering expenses. The Partnership 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.

The board of directors of the General Partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis, beginning with the quarter ending September 30, 2014.

The following table presents cash distributions approved by the board of directors of the General Partner for the periods presented:

Declaration Date	Quarter	Amount per Common Unit		Payment Date	Amount Distributed to Diamondback
					(in thousands)
May 2, 2016	Q1 2016	$	0.149	May 23, 2016	$	10,497
July 21, 2016	Q2 2016	$	0.189	August 22, 2016	$	13,693
October 25, 2016	Q3 2016	$	0.207	November 18, 2016	$	14,997
February 3, 2017	Q4 2016	$	0.258	February 24, 2017	$	18,692
April 28, 2017	Q1 2017	$	0.302	May 25, 2017	$	21,880
July 28, 2017	Q2 2017	$	0.332	August 24, 2017	$	24,286
October 16, 2017	Q3 2017	$	0.337	November 14, 2017	$	24,652
January 31, 2018	Q4 2017	$	0.460	February 26, 2018	$	33,649
April 5, 2018	Q1 2018	$	0.480	April 27, 2018	$	35,112
July 27, 2018	Q2 2018	$	0.600	August 20, 2018	$	43,901
October 23, 2018	Q3 2018	$	0.580	November 19, 2018	$	42,447

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 the Partnership and the Operating Company for each quarter is determined by the board of directors of the Partnership’s 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 the Partnership’s general partner deems necessary or appropriate, if any, and the Partnership’s available cash will generally equal its Adjusted EBITDA (which will be the proportionate share of the available cash distributed to the Partnership by the Operating Company), less as a result of the Tax Election, cash needed for the payment of income taxes payable by the Partnership, if any.

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Earnings Per Unit

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Earnings Per Unit

EARNINGS PER UNIT

The net income per common unit on the consolidated statements of operations is based on the net income (loss) of the Partnership for the years ended December 31, 2018, 2017 and 2016, since this is the amount of net income (loss) that is attributable to the Partnership’s common units.

The Partnership’s net income (loss) is allocated wholly to the common units. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 8—Unitholders’ Equity and Partnership Distributions.

Basic net income per common unit is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested common units granted under the LTIP.

	Year Ended December 31,
	2018		2017		2016
	(In thousands, except per unit amounts)
Net income (loss) attributable to the period	$	143,958	$	111,478	$	(10,899	)
Weighted average common units outstanding:
Basic weighted average common units outstanding	71,546		104,318		83,081
Effect of dilutive securities:
Potential common units issuable	80		65		—
Diluted weighted average common units outstanding	71,626		104,383		83,081
Net income (loss) per common unit, basic	$2.01		$1.07		$(0.13)
Net income (loss) per common unit, diluted	$2.01		$1.07		$(0.13)

The Partnership had the following units that were excluded from the computation of diluted earnings per unit because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per unit in future periods:

	Year Ended December 31,
	2018	2017	2016
	(in thousands)
Restricted stock units	1	40	1,567

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Income Taxes

12 Months Ended

Dec. 31, 2018

Operating Loss Carryforwards [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

As discussed further in Note 1, on March 29, 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. Because the operations of the business continue to be conducted through a pass-through entity, the Operating Company, in which the Partnership and Diamondback have ownership, represents a continuation of the historic pass-through entity for federal income tax purposes. Notwithstanding this federal income tax treatment, the change in the Partnership’s tax status is accounted for under financial accounting rules as a change in the Partnership’s tax status. This accounting treatment results in the Partnership’s financial statements reflecting a deferred tax benefit attributable to the Partnership succeeding to the tax basis of the Partnership’s unitholders in the unitholders’ Partnership units as of the effective date of the conversion.

Subsequent to the Partnership’s change in tax status, the Partnership provides for income taxes under the asset and liability method. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities, specifically the Partnership’s investment in the Operating Company, using enacted tax rates expected to be in effect during the year in which the basis differences reverse. Valuation allowances are established when Management determines it is more likely than not that some portion, or all, of the Partnership’s deferred tax assets will not be realized.

The Partnership’s effective income tax rate was (38.0)% for the year ended December 31, 2018. Total income tax benefit for the year ended December 31, 2018 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to (i) the impact of deferred taxes recognized as a result of the Partnership’s change in tax status, (ii) net income attributable to the non-controlling interest, and (iii) net income attributable to the period prior to the Partnership’s change in federal income tax status. For the year ended December 31, 2018, the Partnership recorded an income tax benefit of approximately $72.8 million related to deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s federal tax status and the Partnership’s succession to the partners’ tax bases in the Partnership at the date of the tax status change.

Prior to May 10, 2018, the effective date of the Partnership’s change in income tax status, the Partnership was treated as a pass-through entity for income tax purposes. As a result, the Partnership’s partners were responsible for federal income taxes on their share of the Partnership’s taxable income.

The components of the provision for income taxes for the year ended December 31, 2018 are as follows:

	Year Ended December 31, 2018
	(In thousands)
Current income tax provision (benefit):
Federal	$	—
State	151
Total current income tax provision	151
Deferred income tax provision (benefit):
Federal	(72,516		)
State	—
Total deferred income tax provision (benefit)	(72,516		)
Total provision for (benefit from) income taxes	$	(72,365	)

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:

	Year Ended December 31, 2018
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	40,008
Impact of net income attributable to the pre-incorporation period	(14,279		)
Impact of nontaxable noncontrolling interest	(24,973		)
State income tax expense (benefit), net of federal tax effect	119
Deferred taxes related to change in tax status	(72,787		)
Other, net	(453		)
Provision for (benefit from) income taxes	$	(72,365	)

The components of the Company’s deferred tax assets and liabilities as of December 31, 2018 are as follows:

	December 31, 2018
	(In thousands)
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$	2,131
Investment in the Operating Company	94,468
Other	284
Total deferred tax assets	96,883
Valuation allowance	—
Net deferred tax assets	96,883
Deferred tax liabilities:
Oil and natural gas properties and equipment	—
Other	—
Total deferred tax liabilities	—
Net deferred tax assets (liabilities)	$	96,883

As of December 31, 2018, the Partnership has net deferred tax assets of approximately $96.9 million, including $72.8 million recorded as a result of the Partnership’s change in tax status. Under federal income tax provisions applicable to the Partnership's change in tax status, the Partnership's basis for federal income tax purposes in its interest in the Operating Company consists primarily of the sum of the Partnership's unitholders' tax bases in their interests in the Partnership on the date of the tax status change. Under federal income tax reporting rules applicable to publicly traded partnerships ("PTPs"), partner information, including partner tax basis information, is required to be provided to the Partnership, but not in sufficient time for the Partnership to finalize its determination of the resultant tax basis in the Operating Company. The deferred tax asset reflected above represents the Partnership’s best estimate of the difference between its tax basis and its basis for financial accounting purposes in the Operating Company. The estimate is subject to revision, which the Partnership does not believe will be material, when the Partnership finalizes its federal income tax computations for 2018. The Partnership has federal net operating loss carryforwards of approximately $8.3 million which may be carried forward indefinitely to offset future taxable income.

Management considers the likelihood that the Partnership’s net operating losses and other deferred tax attributes will be utilized prior to their expiration. At December 31, 2018, Management’s assessment included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities and projected future taxable income. As a result of the assessment, Management determined that it is more likely than not that the Partnership will realize its deferred tax assets.

The Partnership principally operates in the state of Texas. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax attributable to the Partnership’s results which are included in a combined tax return filed by Diamondback. At December 31, 2018, the Partnership did not have any significant uncertain tax positions requiring recognition in the financial statements. In addition to the 2018 tax year, our 2015 through 2017 tax years, periods during which we were organized as a pass-through entity for income tax purposes, remain open to examination by tax authorities.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

The Partnership could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

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Subsequent Events

12 Months Ended

Dec. 31, 2018

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

Cash Distribution

On January 30, 2019, the board of directors of the General Partner approved a cash distribution 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.

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Supplemental Information on Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Supplemental information on oil and natural gas operations

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Partnership’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

	December 31,
	2018			2017
	(In thousands)
Oil and natural gas interests:
Proved	$	845,228		$	589,173
Unproved	871,485			514,724
Total oil and natural gas interests	1,716,713			1,103,897
Accumulated depletion and impairment	(248,296		)	(189,466		)
Net oil and natural gas interests capitalized	$	1,468,417		$	914,431

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

	December 31,
	2018		2017		2016
	(In thousands)
Acquisition costs:
Proved properties	$	256,055	$	55,948	$	31,441
Unproved properties	356,761		287,131		174,385
Total	$	612,816	$	343,079	$	205,826

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and natural gas liquids operations.

	December 31,
	2018			2017			2016
	(In thousands)
Royalty income	$	282,661		$	160,163		$	78,837
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		)
Income tax expense	(422		)	—			—
Results of operations from oil, natural gas and natural gas liquids	$	204,361		$	108,247		$	(4,411	)

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2018, 2017 and 2016 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The changes in estimated proved reserves are as follows:

	Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)
	(In thousands)
Proved Developed and Undeveloped Reserves:
As of December 31, 2015	18,378		3,916		24,308
Purchase of reserves in place	1,138		437		2,315
Extensions and discoveries	5,647		1,477		7,181
Revisions of previous estimates	(2,041	)	74		(5,223	)
Production	(1,778	)	(328	)	(1,490	)
As of December 31, 2016	21,344		5,576		27,091
Purchase of reserves in place	2,106		252		5,245
Extensions and discoveries	7,859		1,813		11,106
Revisions of previous estimates	(2,525	)	(813	)	(3,498	)
Production	(2,899	)	(533	)	(3,549	)
As of December 31, 2017	25,885		6,295		36,395
Purchase of reserves in place	5,394		1,163		16,486
Extensions and discoveries	13,858		3,359		13,992
Revisions of previous estimates	1,140		1,108		564
Production	(4,399	)	(933	)	(5,840	)
As of December 31, 2018	41,878		10,992		61,597
Proved Developed Reserves:
December 31, 2016	12,332		3,247		15,933
December 31, 2017	18,788		4,536		29,256
December 31, 2018	29,526		7,965		49,681
Proved Undeveloped Reserves:
December 31, 2016	9,012		2,329		11,158
December 31, 2017	7,097		1,759		7,139
December 31, 2018	12,352		3,027		11,916

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2018, the Partnership’s extensions and discoveries of 19,549 MBoe resulted primarily from the drilling of 133 new wells and from 138 new proved undeveloped locations added. The Partnership’s positive revisions of previous estimated quantities of 2,342 MBoe were primarily due to changes in type curves and realized prices. The purchase of reserves in place of 9,305 MBoe were due to multiple acquisitions primarily located in Pecos, Reeves and Howard counties within the Permian Basin as well as an acquisition in the Eagle Ford Shale.

During the year ended December 31, 2017, the Partnership’s extensions and discoveries of 11,524 MBoe resulted primarily from the drilling of 96 new wells and from 40 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 3,921 MBoe were primarily due to changes in type curves. The purchase of reserves in place of 3,232 MBoe were due to multiple acquisitions with the largest being located in Pecos, Reeves and Loving counties.

During the year ended December 31, 2016, the Partnership’s extensions and discoveries of 7,125 MBoe resulted primarily from the drilling of 33 new wells and from 32 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 1,968 MBoe were primarily due to technical revisions with the remainder due to lower product pricing. The purchase of reserves in place of 1,575 MBoe were due to multiple acquisitions with the largest being located in Loving and Midland counties.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows are based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Partnership. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Partnership’s proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016:

	December 31,
	2018			2017			2016
	(In thousands)
Future cash inflows	$	2,962,386		$	1,445,883		$	948,090
Future production taxes	(200,079		)	(125,564		)	(69,109		)
Future income tax expense	(273,643		)	(6,932		)	(4,615		)
Future net cash flows	2,488,664			1,313,387			874,366
10% discount to reflect timing of cash flows	(1,349,282		)	(688,039		)	(461,785		)
Standardized measure of discounted future net cash flows	$	1,139,382		$	625,348		$	412,581

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows:

	December 31,
	2018		2017		2016
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	61.46	$	48.21	$	39.64
Natural gas (per Mcf)	$	1.84	$	2.13	$	1.36
Natural gas liquids (per Bbl)	$	25.04	$	19.15	$	11.69

Principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership’s proved reserves are as follows:

	December 31,
	2018			2017			2016
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	625,348		$	412,581		$	395,763
Purchase of minerals in place	180,990			54,662			23,651
Sales of oil and natural gas, net of production costs	(266,055		)	(149,555		)	(74,628		)
Extensions and discoveries	423,540			214,479			104,451
Net changes in prices and production costs	187,592			99,382			(42,155		)
Revisions of previous quantity estimates	52,487			(50,773		)	(42,883		)
Net changes in income taxes	(123,804		)	(1,129		)	51
Accretion of discount	62,867			41,477			39,800
Net changes in timing of production and other	(3,583		)	4,224			8,531
Standardized measure of discounted future net cash flows at the end of the period	$	1,139,382		$	625,348		$	412,581

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL DATA (Unaudited)

	2018
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
Operating income	$	62,443	$	75,406		$	78,603	$	72,368
Income from operations	43,703		54,926			54,846		49,512
Income tax expense (benefit)	—		(71,878		)	764		(1,251		)
Net income	42,896		128,464			50,812		40,705
Net income attributable to non-controlling interest	—		29,060			48,466		41,393
Net income (loss) attributable to Viper Energy Partners LP	$	42,896	$	99,404		$	2,346	$	(688	)
Net income (loss) attributable to common limited partners per unit:
Basic	$	0.38	$	1.36		$	0.05	$	(0.01	)
Diluted	$	0.38	$	1.35		$	0.05	$	(0.01	)

	2017
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
Operating income	$	33,652	$	36,622	$	42,533	$	59,226
Income from operations	21,450		22,479		27,067		42,825
Net income	$	20,652	$	22,149	$	26,607	$	42,070
Net income attributable to common limited partners per unit:
Basic	$	0.22	$	0.23	$	0.24	$	0.37
Diluted	$	0.22	$	0.23	$	0.24	$	0.37

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities at the date of the financial statements.

The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, the recoverability of costs of unevaluated properties, unit–based compensation and estimate of income taxes.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits.

Royalty Income Receivable

Revenue from Contracts with Customers

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the operator. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

Royalty income from oil, natural gas and natural gas liquids sales

The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

Transaction price allocated to remaining performance obligations

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of our royalty income contracts.

Contract balances

Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year endedDecember 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Fair Value of Financial Instruments

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, receivables, payables and a credit agreement. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments.

Oil and Natural Gas Properties

Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write-down is required.

Oil and Natural Gas Properties

The Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property on an annual basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves.

Debt Issuance Costs

The costs are associated with the Partnership’s credit agreement and are being amortized over the term of the credit agreement.

Royalty Interest and Revenue Recognition

Royalty Interest and Revenue Recognition

Royalty interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when control passes to the producer.

Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur any of the costs of exploration, development and operation of the property.

Concentrations

The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Concentrations

The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers.

Investments

Investments

The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method.

Earnings Per Unit

Earnings Per Unit

Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.

Unit-based Compensation

Unit–Based Compensation

Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 7—Unit–Based Compensation.

Income Taxes

Income Taxes

The Partnership uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Partnership is subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 10—Income Taxes. In addition to the 2018 tax year, the Partnership’s 2015 through 2017 tax years, during which the Partnership was organized as a pass-through entity for federal income tax purposes, remain open to examination by tax authorities. As of December 31, 2018 and 2017, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2018, 2017 and 2016, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.

New Accounting Pronouncements

New Accounting Pronouncements

Recently Adopted Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Partnership adopted this standard effective January 1, 2018 using the modified retrospective method. The Partnership utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standard on its total revenues, operating income and the Partnership’s consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Partnership adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of December 31, 2018, the Partnership was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. The Partnership adopted this standard effective January 1, 2019 using the modified retrospective method. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

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Oil and Natural Gas Interests (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Aggregate capitalized costs related to oil and natural gas production activities

Oil and natural gas interests include the following:

	December 31,
	2018			2017
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	845,228		$	589,173
Not subject to depletion	871,485			514,724
Gross oil and natural gas interests	1,716,713			1,103,897
Accumulated depletion and impairment	(248,296		)	(189,466		)
Oil and natural gas interests, net	1,468,417			914,431
Land	5,688			—
Property, net of accumulated depletion and impairment	$	1,474,105		$	914,431
Balance of costs not subject to depletion:
Incurred in 2018	$	476,027
Incurred in 2017	284,371
Incurred in 2016	111,087
Total not subject to depletion	$	871,485

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

	December 31,
	2018			2017
	(In thousands)
Oil and natural gas interests:
Proved	$	845,228		$	589,173
Unproved	871,485			514,724
Total oil and natural gas interests	1,716,713			1,103,897
Accumulated depletion and impairment	(248,296		)	(189,466		)
Net oil and natural gas interests capitalized	$	1,468,417		$	914,431

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Debt (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Schedule of financial covenants

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than 1.0 to 1.0

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Unit-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of valuation assumptions

	2014
Grant-date fair value	$	4.24
Expected volatility	36.0		%
Expected dividend yield	5.9		%
Expected term (in years)	3.0
Risk-free rate	0.99		%

Schedule of unit option activity

The following table presents the unit option activity under the LTIP for the year ended December 31, 2018:

			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2017	7,600		$	18.49
Exercised	(7,600	)	$	18.49
Outstanding at December 31, 2018	—		$	—	0.00	$	—

Schedule of Nonvested Performance-based Units Activity

The following table presents the phantom unit activity under the LTIP for the year ended December 31, 2018:

	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	105,439		$	17.10
Granted	127,402		$	25.54
Vested	(102,811	)	$	19.23
Forfeited	(4,977	)	$	29.71
Unvested at December 31, 2018	125,053		$	23.44

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Partners' Capital and Partnership Distributions (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Schedule of changes in common units

The following table summarizes changes in the number of the Partnership’s common units:

	Common Units
Balance at December 31, 2017	113,882,045
Common units issued in public offerings	10,080,000
Common units vested and issued under the LTIP	110,411
Unit exchange related to tax conversion	(73,150,000	)
Recapitalization related to tax conversion	731,500
Balance at December 31, 2018	51,653,956

The following table summarizes changes in the number of the Partnership’s Class B units:

	Class B Units
Balance at December 31, 2017	—
Unit exchange related to tax conversion	73,150,000
Recapitalization related to tax conversion	(731,500	)
Balance at December 31, 2018	72,418,500

Distributions Made to Limited Partner, by Distribution

The following table presents cash distributions approved by the board of directors of the General Partner for the periods presented:

Declaration Date	Quarter	Amount per Common Unit		Payment Date	Amount Distributed to Diamondback
					(in thousands)
May 2, 2016	Q1 2016	$	0.149	May 23, 2016	$	10,497
July 21, 2016	Q2 2016	$	0.189	August 22, 2016	$	13,693
October 25, 2016	Q3 2016	$	0.207	November 18, 2016	$	14,997
February 3, 2017	Q4 2016	$	0.258	February 24, 2017	$	18,692
April 28, 2017	Q1 2017	$	0.302	May 25, 2017	$	21,880
July 28, 2017	Q2 2017	$	0.332	August 24, 2017	$	24,286
October 16, 2017	Q3 2017	$	0.337	November 14, 2017	$	24,652
January 31, 2018	Q4 2017	$	0.460	February 26, 2018	$	33,649
April 5, 2018	Q1 2018	$	0.480	April 27, 2018	$	35,112
July 27, 2018	Q2 2018	$	0.600	August 20, 2018	$	43,901
October 23, 2018	Q3 2018	$	0.580	November 19, 2018	$	42,447

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Earnings Per Unit (Tables)

12 Months Ended

Dec. 31, 2018

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

Schedule of basic and diluted net income per common unit

	Year Ended December 31,
	2018		2017		2016
	(In thousands, except per unit amounts)
Net income (loss) attributable to the period	$	143,958	$	111,478	$	(10,899	)
Weighted average common units outstanding:
Basic weighted average common units outstanding	71,546		104,318		83,081
Effect of dilutive securities:
Potential common units issuable	80		65		—
Diluted weighted average common units outstanding	71,626		104,383		83,081
Net income (loss) per common unit, basic	$2.01		$1.07		$(0.13)
Net income (loss) per common unit, diluted	$2.01		$1.07		$(0.13)

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]

The Partnership had the following units that were excluded from the computation of diluted earnings per unit because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per unit in future periods:

	Year Ended December 31,
	2018	2017	2016
	(in thousands)
Restricted stock units	1	40	1,567

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Operating Loss Carryforwards [Line Items]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The components of the provision for income taxes for the year ended December 31, 2018 are as follows:

	Year Ended December 31, 2018
	(In thousands)
Current income tax provision (benefit):
Federal	$	—
State	151
Total current income tax provision	151
Deferred income tax provision (benefit):
Federal	(72,516		)
State	—
Total deferred income tax provision (benefit)	(72,516		)
Total provision for (benefit from) income taxes	$	(72,365	)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:

	Year Ended December 31, 2018
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	40,008
Impact of net income attributable to the pre-incorporation period	(14,279		)
Impact of nontaxable noncontrolling interest	(24,973		)
State income tax expense (benefit), net of federal tax effect	119
Deferred taxes related to change in tax status	(72,787		)
Other, net	(453		)
Provision for (benefit from) income taxes	$	(72,365	)

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

The components of the Company’s deferred tax assets and liabilities as of December 31, 2018 are as follows:

	December 31, 2018
	(In thousands)
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$	2,131
Investment in the Operating Company	94,468
Other	284
Total deferred tax assets	96,883
Valuation allowance	—
Net deferred tax assets	96,883
Deferred tax liabilities:
Oil and natural gas properties and equipment	—
Other	—
Total deferred tax liabilities	—
Net deferred tax assets (liabilities)	$	96,883

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Aggregate capitalized costs related to oil and natural gas production activities

Oil and natural gas interests include the following:

	December 31,
	2018			2017
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	845,228		$	589,173
Not subject to depletion	871,485			514,724
Gross oil and natural gas interests	1,716,713			1,103,897
Accumulated depletion and impairment	(248,296		)	(189,466		)
Oil and natural gas interests, net	1,468,417			914,431
Land	5,688			—
Property, net of accumulated depletion and impairment	$	1,474,105		$	914,431
Balance of costs not subject to depletion:
Incurred in 2018	$	476,027
Incurred in 2017	284,371
Incurred in 2016	111,087
Total not subject to depletion	$	871,485

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

	December 31,
	2018			2017
	(In thousands)
Oil and natural gas interests:
Proved	$	845,228		$	589,173
Unproved	871,485			514,724
Total oil and natural gas interests	1,716,713			1,103,897
Accumulated depletion and impairment	(248,296		)	(189,466		)
Net oil and natural gas interests capitalized	$	1,468,417		$	914,431

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

	December 31,
	2018		2017		2016
	(In thousands)
Acquisition costs:
Proved properties	$	256,055	$	55,948	$	31,441
Unproved properties	356,761		287,131		174,385
Total	$	612,816	$	343,079	$	205,826

Results of Operations for Oil and Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and natural gas liquids operations.

	December 31,
	2018			2017			2016
	(In thousands)
Royalty income	$	282,661		$	160,163		$	78,837
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		)
Income tax expense	(422		)	—			—
Results of operations from oil, natural gas and natural gas liquids	$	204,361		$	108,247		$	(4,411	)

Changes in Estimated Proved Reserves

The changes in estimated proved reserves are as follows:

	Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)
	(In thousands)
Proved Developed and Undeveloped Reserves:
As of December 31, 2015	18,378		3,916		24,308
Purchase of reserves in place	1,138		437		2,315
Extensions and discoveries	5,647		1,477		7,181
Revisions of previous estimates	(2,041	)	74		(5,223	)
Production	(1,778	)	(328	)	(1,490	)
As of December 31, 2016	21,344		5,576		27,091
Purchase of reserves in place	2,106		252		5,245
Extensions and discoveries	7,859		1,813		11,106
Revisions of previous estimates	(2,525	)	(813	)	(3,498	)
Production	(2,899	)	(533	)	(3,549	)
As of December 31, 2017	25,885		6,295		36,395
Purchase of reserves in place	5,394		1,163		16,486
Extensions and discoveries	13,858		3,359		13,992
Revisions of previous estimates	1,140		1,108		564
Production	(4,399	)	(933	)	(5,840	)
As of December 31, 2018	41,878		10,992		61,597
Proved Developed Reserves:
December 31, 2016	12,332		3,247		15,933
December 31, 2017	18,788		4,536		29,256
December 31, 2018	29,526		7,965		49,681
Proved Undeveloped Reserves:
December 31, 2016	9,012		2,329		11,158
December 31, 2017	7,097		1,759		7,139
December 31, 2018	12,352		3,027		11,916

Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Partnership’s proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016:

	December 31,
	2018			2017			2016
	(In thousands)
Future cash inflows	$	2,962,386		$	1,445,883		$	948,090
Future production taxes	(200,079		)	(125,564		)	(69,109		)
Future income tax expense	(273,643		)	(6,932		)	(4,615		)
Future net cash flows	2,488,664			1,313,387			874,366
10% discount to reflect timing of cash flows	(1,349,282		)	(688,039		)	(461,785		)
Standardized measure of discounted future net cash flows	$	1,139,382		$	625,348		$	412,581

Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows:

	December 31,
	2018		2017		2016
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	61.46	$	48.21	$	39.64
Natural gas (per Mcf)	$	1.84	$	2.13	$	1.36
Natural gas liquids (per Bbl)	$	25.04	$	19.15	$	11.69

Principal Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership’s proved reserves are as follows:

	December 31,
	2018			2017			2016
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	625,348		$	412,581		$	395,763
Purchase of minerals in place	180,990			54,662			23,651
Sales of oil and natural gas, net of production costs	(266,055		)	(149,555		)	(74,628		)
Extensions and discoveries	423,540			214,479			104,451
Net changes in prices and production costs	187,592			99,382			(42,155		)
Revisions of previous quantity estimates	52,487			(50,773		)	(42,883		)
Net changes in income taxes	(123,804		)	(1,129		)	51
Accretion of discount	62,867			41,477			39,800
Net changes in timing of production and other	(3,583		)	4,224			8,531
Standardized measure of discounted future net cash flows at the end of the period	$	1,139,382		$	625,348		$	412,581

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of Quarterly Financial Information [Table Text Block]

	2018
	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
Operating income	$	62,443	$	75,406		$	78,603	$	72,368
Income from operations	43,703		54,926			54,846		49,512
Income tax expense (benefit)	—		(71,878		)	764		(1,251		)
Net income	42,896		128,464			50,812		40,705
Net income attributable to non-controlling interest	—		29,060			48,466		41,393
Net income (loss) attributable to Viper Energy Partners LP	$	42,896	$	99,404		$	2,346	$	(688	)
Net income (loss) attributable to common limited partners per unit:
Basic	$	0.38	$	1.36		$	0.05	$	(0.01	)
Diluted	$	0.38	$	1.35		$	0.05	$	(0.01	)

	2017
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
Operating income	$	33,652	$	36,622	$	42,533	$	59,226
Income from operations	21,450		22,479		27,067		42,825
Net income	$	20,652	$	22,149	$	26,607	$	42,070
Net income attributable to common limited partners per unit:
Basic	$	0.22	$	0.23	$	0.24	$	0.37
Diluted	$	0.22	$	0.23	$	0.24	$	0.37

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Organization and Basis of Presentation (Details) - USD ($)	1 Months Ended	2 Months Ended	12 Months Ended
	Jul. 31, 2018	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 31, 2019	May 10, 2018
Limited Partners' Capital Account [Line Items]
Class B Units Issued			72,418,500	0		72,418,500
General Partners' Contributed Capital							$ 1,000,000
Limited Partners' Contributed Capital							$ 1,000,000
Limited partners capital account, percentage of distribution							8.00%
Number of Class B Units Converted		731,500
Partners' Capital Account, Units, Converted		731,500
Limited Partners' Capital Account, Distribution Amount		$ 10,000	$ 98,333,000	$ 41,367,000	$ 9,574,000
General Partner [Member]
Limited Partners' Capital Account [Line Items]
Percent of General Partner interest		36.00%	100.00%
Limited Partners' Capital Account, Distribution Amount			$ 0	$ 0	$ 0
Diamondback Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Percent of limited partnership interest	59.00%	64.00%	59.00%
Units of Partnership Interest, Amount							73,150,000
Class B Units Issued							73,150,000

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Summary of Significant Accounting Policies - Oil and Natural Gas Properties, Capitalized Interest, and Debt Issuance Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) $ / Boe	Dec. 31, 2017 USD ($) $ / Boe	Dec. 31, 2016 USD ($) $ / Boe
Accounting Policies [Abstract]
Average depletion rate per barrel equivalent unit of production | $ / Boe	9.33	10.07	12.67
Depletion of oil and gas properties	$ 58,830	$ 40,519	$ 29,820
Impairment of oil and gas properties	0	0	47,469
Debt issuance costs, net of accumulated amortizations	5,457	4,419	2,159
Debit issuance costs, accumulated amortization	$ 2,151	$ 1,415	$ 826

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Summary of Significant Accounting Policies - Concentrations and Investments (Details) - Customer Concentration Risk [Member] - Royalty Interest Revenue [Member]	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Shell Trading [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	31.00%	47.00%	57.00%
Concho Resources, Inc [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	16.00%
Trafigura Trading LLC [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	11.00%
RSP Permian LLC [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue		23.00%	32.00%

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Dec. 31, 2014
Investment [Line Items]
Restricted cash					$ 500
State income tax expense	$ 151
Impact of adoption of ASU 2016-01	(18,651)
Loss on revaluation of investment	(550)	$ 0	$ 0
Limited Partner [Member] | Common Class A [Member]
Investment [Line Items]
Impact of adoption of ASU 2016-01	(18,651)			$ (18,651)
Other Noncurrent Assets [Member]
Investment [Line Items]
Fair value investment	$ 14,525

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Acquisitions (Details) $ in Thousands		12 Months Ended
	Aug. 15, 2018 USD ($) a	Dec. 31, 2018 USD ($) a	Dec. 31, 2017 USD ($) a shares	Dec. 31, 2016 USD ($) a
Business Acquisition [Line Items]
Payments to Acquire Mineral Rights | $		$ 610,131	$ 344,079	$ 205,721
Series of Individually Immaterial Business Acquisitions [Member]
Business Acquisition [Line Items]
Mineral Properties Acquired, Net Royalty Acres		3,585	3,157	2,142
Payments to Acquire Mineral Rights | $		$ 440,400	$ 343,100	$ 205,700
Mineral Properties, Net Royalty Acres		14,841	9,570
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares			174,513
Diamondback Limited Partner [Member]
Business Acquisition [Line Items]
Mineral Properties Acquired, Gross Acres	32,424
Mineral Properties Acquired, Net Royalty Acres	1,696
Payments to Acquire Mineral Rights | $	$ 175,000
Percentage of mineral acres operated by affiliate	80.00%

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Oil and Natural Gas Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Subject to depletion	$ 845,228	$ 589,173
Not subject to depletion	871,485	514,724
Gross oil and natural gas interests	1,716,713	1,103,897
Accumulated depletion and impairment	(248,296)	(189,466)
Oil and natural gas interests, net	1,468,417	914,431
Land	5,688	0
Property, net	1,474,105	914,431
Balance of costs not subject to depletion:	476,027	284,371	$ 111,087
Impairment	$ 0	$ 0	$ 47,469
Minimum [Member]
Property, Plant and Equipment [Line Items]
Anticipated number of years for inclusion of costs in amortization calculation	3
Maximum [Member]
Property, Plant and Equipment [Line Items]
Anticipated number of years for inclusion of costs in amortization calculation	5

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Debt - Credit Facility (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) redetermindation
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000.0
Current borrowing capacity	$ 555.0
Number of additional redeterminations that may be requested | redetermindation	3
Period of redeterminations	12 months
Amount outstanding under credit facility	$ 411.0
Remaining borrowing capacity	$ 144.0
Federal Funds Effective Swap Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Minimum [Member]
Line of Credit Facility [Line Items]
Commitment fee on the unused portion of the borrowing base	0.375%
Minimum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.75%
Minimum [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.75%
Maximum [Member]
Line of Credit Facility [Line Items]
Commitment fee on the unused portion of the borrowing base	0.50%
Maximum [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.75%
Maximum [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.75%

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Debt - Financial Covenants (Details) $ in Millions	Dec. 31, 2018 USD ($)
Line of Credit Facility [Line Items]
Maximum issuance of unsecured debt	$ 400.0
Reduction of borrowing base	25.00%
Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX, not greater than 4.0	4.0
Minimum [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, not less than 1.0	1.0

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Related Party Transactions (Details)			12 Months Ended
	Aug. 15, 2018 USD ($) a	Jun. 23, 2014 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Related Party Transaction [Line Items]
Payments to Acquire Mineral Rights			$ 610,131,000	$ 344,079,000	$ 205,721,000
State income tax expense			151,000
General Partner [Member] | Partnership Agreement [Member]
Related Party Transaction [Line Items]
Incurred costs for transactions with related party			2,460,000	2,460,000	0
Affiliated Entity [Member] | Advisory Services Agreement [Member]
Related Party Transaction [Line Items]
Incurred costs for transactions with related party			0	0	0
Advisory services agreement, annual fee		$ 500,000
Diamondback Limited Partner [Member]
Related Party Transaction [Line Items]
Mineral Properties Acquired, Gross Acres | a	32,424
Mineral Properties Acquired, Net Royalty Acres | a	1,696
Percentage of mineral acres operated by affiliate	80.00%
Payments to Acquire Mineral Rights	$ 175,000,000
Revenue from Related Parties			2,461,000	$ 106,000	$ 300,000
Revenue from related parties on new leases			$ 647,000
Number of leases extended			13	2	6
Average price per acre			$ 4,149	$ 7,459	$ 1,371
Number of new leases			1
Average price per acre on new leases			$ 18,002

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Unit-Based Compensation Additional Disclosures (Details) - USD ($) $ in Millions		12 Months Ended
	Jun. 17, 2014	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units reserved for issuance		8,967,545
Equity-based compensation		$ 2.8	$ 2.4	$ 3.8
Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit options granted	2,500,000
Vesting percentage for next three anniversaries	33.00%

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Unit-Based Compensation Valuation Assumptions (Details) - Unit Options [Member]	12 Months Ended
	Dec. 31, 2014 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 4.24
Expected volatility	36.00%
Expected dividend yield	5.90%
Expected term (in years)	3 years
Risk-free rate	0.99%

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Unit-Based Compensation Unit Option Activity (Details) - Unit Options [Member] $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) $ / shares shares
Number of Options
Outstanding at December 31, 2017 | shares	7,600
Exercised | shares	(7,600)
Outstanding at December 31, 2018 | shares	0
Weighted Average Exercise Price
Outstanding at December 31, 2017 | $ / shares	$ 18.49
Exercised | $ / shares	18.49
Outstanding at December 31, 2018 | $ / shares	$ 0.00
Outstanding at end of period, remaining term	0 years
Outstanding at end of period, intrinsic value | $	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value | $	$ 200

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Unit-Based Compensation Phantom Units (Details) - Phantom Share Units (PSUs) [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Unvested at December 31, 2017 | shares	105,439
Granted | shares	127,402
Vested | shares	(102,811)
Forfeited | shares	(4,977)
Unvested at December 31, 2018 | shares	125,053
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested at December 31, 2017 | $ / shares	$ 17.10
Granted | $ / shares	25.54
Vested | $ / shares	19.23
Forfeited | $ / shares	29.71
Unvested at December 31, 2018 | $ / shares	$ 23.44
Aggregate fair value of phantom units that vested during period | $	$ 2.0
Unrecognized compensation cost related to unvested phantom units | $	$ 1.6
Unrecognized compensation cost related to unvested unit options, period of recognition	11 months 22 days

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Partners' Capital and Partnership Distributions (Details) - USD ($) $ in Thousands	1 Months Ended			2 Months Ended	12 Months Ended
	Jul. 31, 2018	Jul. 31, 2017	Jan. 31, 2017	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 31, 2019	May 10, 2018
Limited Partners' Capital Account [Line Items]
Class B Units Outstanding					72,418,500	0		72,418,500
Common units issued					51,653,956	113,882,045
Common units outstanding					51,653,956	113,882,045
Partners' Capital Account, Units, Unit-based Compensation					110,411
Repayments of Lines of Credit					$ 374,000	$ 305,500	$ 78,000
Diamondback Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Percent of limited partnership interest	59.00%			64.00%	59.00%
Class B Units Outstanding									73,150,000
Follow-on Public Offering [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering					10,080,000
Sale of Stock, Number of Shares Issued in Transaction	10,080,000	16,100,000	9,775,000
Sale of Stock, Consideration Received on Transaction	$ 303,100	$ 232,500	$ 147,500
Repayments of Lines of Credit			$ 120,500
Follow-on Public Offering [Member] | Non-Guarantor Subsidiaries [Member]
Limited Partners' Capital Account [Line Items]
Long-term Debt, Gross	$ 361,500
Over-Allotment Option [Member]
Limited Partners' Capital Account [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	1,080,000	2,100,000	1,275,000
Common Class A [Member]
Limited Partners' Capital Account [Line Items]
Recapitalization related to tax conversion, units					731,500
Unit exchange related to tax conversion, units					(73,150,000)
Capital Unit, Class B [Member]
Limited Partners' Capital Account [Line Items]
Recapitalization related to tax conversion, units					(731,500)
Unit exchange related to tax conversion, units					73,150,000
Diamondback Energy, Inc. [Member] | Over-Allotment Option [Member]
Limited Partners' Capital Account [Line Items]
Sale of Stock, Number of Shares Issued in Transaction		700,000
Affiliated Entity [Member] | Over-Allotment Option [Member]
Limited Partners' Capital Account [Line Items]
Sale of Stock, Number of Shares Issued in Transaction		3,000,000
Executive Officer [Member] | Over-Allotment Option [Member]
Limited Partners' Capital Account [Line Items]
Sale of Stock, Number of Shares Issued in Transaction		114,000
Partnership Credit Facility [Member] | Follow-on Public Offering [Member]
Limited Partners' Capital Account [Line Items]
Repayments of Lines of Credit		$ 152,800

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Partnership Distributions (Details) - USD ($)	2 Months Ended	3 Months Ended											12 Months Ended
	Jun. 30, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Distribution Made to Limited Partner [Line Items]
Limited Partners' Capital Account, Distribution Amount	$ 10,000												$ 98,333,000	$ 41,367,000	$ 9,574,000
Cash Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Declaration Date		Oct. 23, 2018	Jul. 27, 2018	Apr. 05, 2018	Jan. 31, 2018	Oct. 16, 2017	Jul. 28, 2017	Apr. 28, 2017	Feb. 03, 2017	Oct. 25, 2016	Jul. 21, 2016	May 02, 2016
Cash distributions, distribution period after quarter end													60 days
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.580	$ 0.600	$ 0.480	$ 0.460	$ 0.337	$ 0.332	$ 0.302	$ 0.258	$ 0.207	$ 0.189	$ 0.149
Distribution Made to Limited Partner, Distribution Date		Nov. 19, 2018	Aug. 20, 2018	Apr. 27, 2018	Feb. 26, 2018	Nov. 14, 2017	Aug. 24, 2017	May 25, 2017	Feb. 24, 2017	Nov. 18, 2016	Aug. 22, 2016	May 23, 2016
Diamondback Limited Partner [Member] | Cash Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Limited Partners' Capital Account, Distribution Amount		$ 42,447,000	$ 43,901,000	$ 35,112,000	$ 33,649,000	$ 24,652,000	$ 24,286,000	$ 21,880,000	$ 18,692,000	$ 14,997,000	$ 13,693,000	$ 10,497,000

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Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Net income (loss) attributable to the period	$ (688)	$ 2,346	$ 99,404	$ 42,896					$ 143,958	$ 111,478	$ (10,899)
Weighted-average common units outstanding, basic									71,546	104,318	83,081
Net income per common unit, basic	$ (0.01)	$ 0.05	$ 1.36	$ 0.38	$ 0.37	$ 0.24	$ 0.23	$ 0.22	$ 2.01	$ 1.07	$ (0.13)
Dilutive Securities, Effect on Basic Earnings Per Share [Abstract]
Potential common units issuable									80	65	0
Earnings Per Share, Diluted [Abstract]
Weighted-average common units outstanding, diluted									71,626	104,383	83,081
Net income per common unit, diluted	$ (0.01)	$ 0.05	$ 1.35	$ 0.38	$ 0.37	$ 0.24	$ 0.23	$ 0.22	$ 2.01	$ 1.07	$ (0.13)
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									1	40	1,567

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Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
Effective income tax rate reconciliation, percent					(37.98%)
Current federal tax expense (benefit)					$ 0
State income tax expense					151
Current income tax expense (benefit)					151
Deferred federal income tax expense (benefit)					(72,516)
Deferred state and local income tax expense (benefit)					0
Total deferred income tax provision (benefit)					(72,516)	$ 0	$ 0
Total provision for (benefit from) income taxes	$ (1,251)	$ 764	$ (71,878)	$ 0	(72,365)	$ 0	$ 0
Income tax expense (benefit) at the federal statutory rate (21%)					40,008
Impact of net income attributable to the pre-incorporation period					(14,279)
Impact of nontaxable noncontrolling interest					(24,973)
State income tax expense (benefit), net of federal tax effect					119
Deferred taxes related to change in tax status					(72,787)
Other, net					$ (453)
Income tax expense (benefit) at the federal statutory rate, percent					21.00%
Net operating loss and interest expense carryforwards (indefinite life carryforward)	2,131				$ 2,131
Investment in the Operating Company	94,468				94,468
Other	284				284
Total deferred tax assets	96,883				96,883
Valuation allowance	0				0
Net deferred tax assets	96,883				96,883
Oil and natural gas properties and equipment	0				0
Other	0				0
Total deferred tax liabilities	0				0
Net deferred tax assets (liabilities)	96,883				96,883
Deferred tax assets, operating loss carryforwards, not subject to expiration	$ 8,286				$ 8,286

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Subsequent Events (Details) - Cash Distribution [Member] - $ / shares		3 Months Ended
	Jan. 30, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.580	$ 0.600	$ 0.480	$ 0.460	$ 0.337	$ 0.332	$ 0.302	$ 0.258	$ 0.207	$ 0.189	$ 0.149
Subsequent Event [Member]
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.510

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Oil and natural gas interests:
Proved properties	$ 845,228	$ 589,173
Unproved properties	871,485	514,724
Total oil and natural gas interests	1,716,713	1,103,897
Accumulated depletion and impairment	(248,296)	(189,466)
Net oil and natural gas interests capitalized	$ 1,468,417	$ 914,431

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved properties	$ 256,055	$ 55,948	$ 31,441
Unproved properties	356,761	287,131	174,385
Total	$ 612,816	$ 343,079	$ 205,826

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) Results of Operation from Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue	$ 72,368	$ 78,603	$ 75,406	$ 62,443	$ 59,226	$ 42,533	$ 36,622	$ 33,652	$ 288,820	$ 172,033	$ 79,146
Production and ad valorem taxes									(19,048)	(10,608)	(5,544)
Depletion									(58,830)	(40,519)	(29,820)
Impairment									0	0	(47,469)
Income tax expense									(422)	0	0
Results of operations from oil, natural gas and natural gas liquids									204,361	108,247	(4,411)
Royalty [Member]
Revenue									282,661	160,163	78,837
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Gathering and transportation									$ 0	$ (789)	$ (415)

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) Changes in Estimated Proved Reserves (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2018 Mcf bbl	Dec. 31, 2017 Mcf bbl	Dec. 31, 2016 Mcf bbl
Reserve Quantities [Line Items]
Purchase of reserves in place	9,305	3,232	1,575
Extensions and discoveries	19,549	11,524	7,125
Revisions of previous estimates	2,342	(3,921)	(1,968)
Development Wells Drilled, Net Productive	133	96	33
Proved Undeveloped Reserves Number of Wells Added	138	40	32
Oil [Member]
Reserve Quantities [Line Items]
Beginning of the period	25,885	21,344	18,378
Purchase of reserves in place	5,394	2,106	1,138
Extensions and discoveries	13,858	7,859	5,647
Revisions of previous estimates	1,140	(2,525)	(2,041)
Production	(4,399)	(2,899)	(1,778)
End of period	41,878	25,885	21,344
Proved Developed Reserves (Volume)	29,526	18,788	12,332
Proved Undeveloped Reserve (Volume)	12,352	7,097	9,012
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning of the period	6,295	5,576	3,916
Purchase of reserves in place	1,163	252	437
Extensions and discoveries	3,359	1,813	1,477
Revisions of previous estimates	1,108	(813)	74
Production	(933)	(533)	(328)
End of period	10,992	6,295	5,576
Proved Developed Reserves (Volume)	7,965	4,536	3,247
Proved Undeveloped Reserve (Volume)	3,027	1,759	2,329
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of the period | Mcf	36,395	27,091	24,308
Purchase of reserves in place | Mcf	16,486	5,245	2,315
Extensions and discoveries | Mcf	13,992	11,106	7,181
Revisions of previous estimates | Mcf	564	(3,498)	(5,223)
Production | Mcf	(5,840)	(3,549)	(1,490)
End of period | Mcf	61,597	36,395	27,091
Proved Developed Reserves (Volume) | Mcf	49,681	29,256	15,933
Proved Undeveloped Reserve (Volume) | Mcf	11,916	7,139	11,158

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Future cash inflows	$ 2,962,386	$ 1,445,883	$ 948,090
Future production taxes	(200,079)	(125,564)	(69,109)
Future income tax expense	(273,643)	(6,932)	(4,615)
Future net cash flows	2,488,664	1,313,387	874,366
10% discount to reflect timing of cash flows	(1,349,282)	(688,039)	(461,785)
Standardized measure of discounted future net cash flows	$ 1,139,382	$ 625,348	$ 412,581	$ 395,763

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids (Details)	12 Months Ended
	Dec. 31, 2018 $ / Mcf $ / bbl	Dec. 31, 2017 $ / Mcf $ / bbl	Dec. 31, 2016 $ / Mcf $ / bbl
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Unweighted Arithmetic Average First-Day-of-the-Month Prices	61.46	48.21	39.64
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Unweighted Arithmetic Average First-Day-of-the-Month Prices | $ / Mcf	1.84	2.13	1.36
Natural Gas Liquids [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Unweighted Arithmetic Average First-Day-of-the-Month Prices	25.04	19.15	11.69

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Supplemental Information on Oil and Natural Gas Operations (Unaudited) Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at the beginning of the period	$ 625,348	$ 412,581	$ 395,763
Purchase of minerals in place	180,990	54,662	23,651
Sales of oil and natural gas, net of production costs	(266,055)	(149,555)	(74,628)
Extensions and discoveries	423,540	214,479	104,451
Net changes in prices and production costs	187,592	99,382	(42,155)
Revisions of previous quantity estimates	52,487	(50,773)	(42,883)
Net changes in income taxes	(123,804)	(1,129)	51
Accretion of discount	62,867	41,477	39,800
Net changes in timing of production and other	(3,583)	4,224	8,531
Standardized measure of discounted future net cash flows at the end of the period	$ 1,139,382	$ 625,348	$ 412,581

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Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenue	$ 72,368	$ 78,603	$ 75,406	$ 62,443	$ 59,226	$ 42,533	$ 36,622	$ 33,652	$ 288,820	$ 172,033	$ 79,146
Income from operations	49,512	54,846	54,926	43,703	42,825	27,067	22,479	21,450	202,987	113,821	(9,311)
Income tax expense (benefit)	(1,251)	764	(71,878)	0					(72,365)	0	0
Net income	40,705	50,812	128,464	42,896	$ 42,070	$ 26,607	$ 22,149	$ 20,652	262,877	111,478	(10,899)
Net income attributable to non-controlling interest	41,393	48,466	29,060	0					118,919	0	0
Net income (loss) attributable to the period	$ (688)	$ 2,346	$ 99,404	$ 42,896					$ 143,958	$ 111,478	$ (10,899)
Net income per common unit, basic	$ (0.01)	$ 0.05	$ 1.36	$ 0.38	$ 0.37	$ 0.24	$ 0.23	$ 0.22	$ 2.01	$ 1.07	$ (0.13)
Net income per common unit, diluted	$ (0.01)	$ 0.05	$ 1.35	$ 0.38	$ 0.37	$ 0.24	$ 0.23	$ 0.22	$ 2.01	$ 1.07	$ (0.13)