Viper Energy, Inc. - Quarter Report: 2018 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



ý	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED March 31, 2018



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)

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 past 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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	o	Accelerated Filer	ý

Non-Accelerated Filer	o	Smaller Reporting Company	o

		Emerging Growth Company	ý

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. ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

As of April 27, 2018, 113,882,045 common limited partner units of the registrant were outstanding.

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VIPER ENERGY PARTNERS LP

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2018

TABLE OF CONTENTS



	Page
Glossary of Oil and Natural Gas Terms	ii
Glossary of Certain Other Terms	iii
Cautionary Statement Regarding Forward-Looking Statements	iv

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets	1
Consolidated Statements of Operations	2
Consolidated Statements of Unitholders’ Equity	3
Consolidated Statements of Cash Flows	4
Notes to Consolidated Financial Statements	5

Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations	13

Item 3. Quantitative and Qualitative Disclosures about Market Risk	20

Item 4. Controls and Procedures	21

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	22

Item 1A. Risk Factors	22

Item 6. Exhibits	22

Signatures	23

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and gas terms that are used in this Quarterly Report on Form 10-Q (this “report”):



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	BOE 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.
Crude oil	Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Gross acres or gross wells	The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal wells	Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
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.
MMBtu	Million British Thermal Units.
Net acres or net wells	The sum of the fractional working interest owned in gross acres.
Oil and natural gas properties	Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
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 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.
Reserves	The 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 are not 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.
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.
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.

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GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this report:



Diamondback	Diamondback Energy, Inc., a Delaware corporation.
Exchange Act	The Securities Exchange Act of 1934, as amended.
GAAP	Accounting principles generally accepted in the United States.
General Partner	Viper Energy Partners GP LLC, a Delaware limited liability company, and the General Partner of the Partnership.
IPO	The Partnership’s initial public offering.
LTIP	Viper Energy Partners LP Long Term Incentive Plan.
Partnership	Viper Energy Partners LP, a Delaware limited partnership.
Partnership agreement	The first amended and restated agreement of limited partnership, dated June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the IPO.
Predecessor	Viper Energy Partners LLC, a Delaware limited liability company, and a wholly owned subsidiary of the Partnership.
SEC	United States Securities and Exchange Commission.
Securities Act	The Securities Act of 1933, as amended.
Wells Fargo	Wells Fargo Bank, National Association.

iii

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this 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 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 report, including those detailed under Part II. Item 1A. Risk Factors in this 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 and pending 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.

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.

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Viper Energy Partners LP

Consolidated Balance Sheets

(Unaudited)



	March 31,			December 31,
	2018			2017

	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	18,151		$	24,197
Royalty income receivable	28,873			25,754
Royalty income receivable—related party	6,505			5,142
Other current assets	361			355
Total current assets	53,890			55,448
Property:
Oil and natural gas interests, full cost method of accounting ($630,916 and $514,724 excluded from depletion at March 31, 2018 and December 31, 2017, respectively)	1,258,327			1,103,897
Accumulated depletion and impairment	(200,992		)	(189,466		)
Oil and natural gas interests, net	1,057,335			914,431
Funds held in escrow	—			6,304
Other assets	18,824			36,854
Total assets	$	1,130,049		$	1,013,037
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	576		$	2,960
Other accrued liabilities	1,918			2,669
Total current liabilities	2,494			5,629
Long-term debt	240,500			93,500
Total liabilities	242,994			99,129
Commitments and contingencies (Note 11)
Unitholders’ equity:
Common units (113,882,045 units issued and outstanding as of March 31, 2018 and as of December 31, 2017 )	887,055			913,908
Total unitholders’ equity	887,055			913,908
Total liabilities and unitholders’ equity	$	1,130,049		$	1,013,037

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended March 31,
	2018			2017
	(In thousands, except per unit amounts)
Operating income:
Royalty income	$	62,393		$	32,050
Lease bonus income	—			1,602
Other operating income	50			—
Total operating income	62,443			33,652
Costs and expenses:
Production and ad valorem taxes	4,239			2,070
Gathering and transportation	265			143
Depletion	11,525			7,847
General and administrative expenses	2,711			2,142
Total costs and expenses	18,740			12,202
Income from operations	43,703			21,450
Other income (expense):
Interest expense, net	(2,098		)	(612		)
Gain on revaluation of investment	899			—
Other income (expense), net	392			(186		)
Total other expense, net	(807		)	(798		)
Net income	$	42,896		$	20,652

Net income attributable to common limited partners per unit:
Basic and Diluted	$	0.38		$	0.22
Weighted average number of limited partner units outstanding:
Basic	113,901			94,969
Diluted	113,991			94,979

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Unitholders' Equity

(Unaudited)



	Limited Partners
	Common
	Units	Amount
		(In thousands)
Balance at December 31, 2016	87,800	$	547,898
Net proceeds from the issuance of common units - public	9,575	147,523
Unit-based compensation		819
Distributions to public		(6,482		)
Distributions to Diamondback		(18,692		)
Net income		20,652
Balance at March 31, 2017	97,375	$	691,718

Balance at December 31, 2017	113,882	$	913,908
Impact of adoption of ASU 2016-01 (Note 2)		(18,651		)
Unit-based compensation		1,288
Distributions to public		(18,737		)
Distributions to Diamondback		(33,649		)
Net income		42,896
Balance at March 31, 2018	113,882	$	887,055

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Cash Flows

(Unaudited)



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Cash flows from operating activities:
Net income	$	42,896		$	20,652
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion	11,525			7,847
Gain on revaluation of investment	(899		)	—
Amortization of debt issuance costs	155			133
Non-cash unit-based compensation	1,288			819
Changes in operating assets and liabilities:
Restricted cash	—			500
Royalty income receivable	(3,119		)	826
Royalty income receivable—related party	(1,363		)	(3,481		)
Accounts payable and other accrued liabilities	(1,265		)	(1,187		)
Other current assets	(6		)	(44		)
Net cash provided by operating activities	49,212			26,065
Cash flows from investing activities:
Acquisition of mineral interests	(149,994		)	(8,579		)
Proceeds from the sale of investments	125			—
Net cash used in investing activities	(149,869		)	(8,579		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	147,000			—
Repayment on credit facility	—			(120,500		)
Debt issuance costs	(3		)	(1		)
Proceeds from public offerings	—			147,725
Public offering costs	—			(186		)
Distributions to partners	(52,386		)	(25,174		)
Net cash provided by financing activities	94,611			1,864
Net (decrease) increase in cash	(6,046		)	19,350
Cash and cash equivalents at beginning of period	24,197			9,213
Cash and cash equivalents at end of period	$	18,151		$	28,563

Supplemental disclosure of cash flow information:
Interest paid	$	2,072		$	582

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Notes to Consolidated Financial Statements

(Unaudited)

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 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 March 31, 2018, Viper Energy Partners GP LLC (the “General Partner”), held a 100% non-economic general partner interest in the Partnership and Diamondback had an approximate 64% limited partner interest in the Partnership. Diamondback owns and controls the General Partner.

Basis of Presentation

The accompanying consolidated financial statements and related notes thereto were prepared in conformity with GAAP. All material intercompany balances and transactions are eliminated in consolidation.

These financial statements have been prepared by the Partnership without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2017, which contains a summary of the Partnership’s significant accounting policies and other disclosures.

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 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 interests and unit–based compensation.

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 is 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 three months ended March 31, 2018, the Partnership recorded a gain of $0.9 million which then increased the Partnership’s investment balance to $16.0 million, which is included in other assets in the accompanying consolidated balance sheets.

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Viper Energy Partners LP

Notes to Financial Statements - (Continued)

(unaudited)

New Accounting Pronouncements

Recently Issued Pronouncements

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. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of March 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. Therefore, the Partnership believes the adoption of this update will not have an impact 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 believes the adoption of this update will not have an impact 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.

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Viper Energy Partners LP

Notes to Financial Statements - (Continued)

(unaudited)

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Impact of ASC Topic 606 Adoption

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.

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 purchaser. Virtually all of the Partnership’s contracts’ pricing provisions 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 purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue.

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 days’ 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 three months ended March 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.

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Viper Energy Partners LP

Notes to Financial Statements - (Continued)

(unaudited)

4. ACQUISITIONS

During the three months ended March 31, 2018, the Partnership acquired mineral interests underlying 967 net royalty acres for an aggregate purchase price of approximately $158.1 million and, as of March 31, 2018, had mineral interests underlying 10,537 net royalty acres. The Partnership funded these acquisitions with borrowings under its revolving credit facility.

5. OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:



	March 31,			December 31,
	2018			2017

	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	627,411		$	589,173
Not subject to depletion	630,916			514,724
Gross oil and natural gas interests	1,258,327			1,103,897
Accumulated depletion and impairment	(200,992		)	(189,466		)
Oil and natural gas interests, net	$	1,057,335		$	914,431

Balance of acquisition costs not subject to depletion
Incurred in 2018	$	120,802
Incurred in 2017	284,371
Incurred in 2016	158,157
Incurred in 2015	28,806
Incurred in 2014	38,780
Total not subject to depletion	$	630,916

Costs associated with unevaluated interests 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.

6. DEBT

Credit Agreement-Wells Fargo Bank

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended, 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 $400.0 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 November 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period. As of March 31, 2018, the borrowing base was set at $400.0 million, and the Partnership had $240.5 million of outstanding borrowings and $159.5 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 Partnership that is equal to an alternative 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

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Viper Energy Partners LP

Notes to Financial Statements - (Continued)

(unaudited)

annum in the case of the alternative 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. The Partnership 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 of the assets of the Partnership and its subsidiary.

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 debt to EBITDAX		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 March 31, 2018, the Partnership was in compliance with the financial covenants under its credit agreement. The lenders may accelerate all of the indebtedness under the Partnership’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 the Partnership’s credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

7. RELATED PARTY TRANSACTIONS

Partnership Agreement

In connection with the closing of the IPO, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated June 23, 2014 (the “Partnership Agreement”). 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 three months ended March 31, 2018 and 2017, the General Partner allocated $0.6 million 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 provides 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 has an initial term of two years commencing on June 23, 2014, and continues for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either

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Viper Energy Partners LP

Notes to Financial Statements - (Continued)

(unaudited)

party upon 30 days prior written notice. For the three months ended March 31, 2018 and 2017, the Partnership did not pay any costs 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.

Lease Bonus

During the three months ended March 31, 2018, Diamondback did not pay the Partnership any lease bonus payments. During the three months ended March 31, 2017, Diamondback paid the Partnership $1,500 in lease bonus payments to extend the term of one lease, reflecting an average bonus of $400 per acre.

8. 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. As of March 31, 2018, a total of 9,070,356 common units had 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 three months ended March 31, 2018, the Partnership incurred $1.3 million of unit–based compensation.

Phantom Units

Under the LTIP, the board of directors of the General Partner is authorized to issue phantom units to eligible employees and non-employee directors. 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 following table presents the phantom unit activity under the LTIP for the three months ended March 31, 2018:



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	105,439		$	17.10
Granted	101,403		$	23.18
Vested	(39,147	)	$	22.30
Unvested at March 31, 2018	167,695		$	19.56

The aggregate fair value of phantom units that vested during the three months ended March 31, 2018 was $0.9 million. As of March 31, 2018, the unrecognized compensation cost related to unvested phantom units was $2.4 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.

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9. UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and common unit partnership interests. The general partner interest is a non-economic interest and is not entitled to any cash distributions.

At March 31, 2018, the Partnership had a total of 113,882,045 common units issued and outstanding, of which 73,150,000 common units were owned by Diamondback, representing approximately 64% of the total Partnership common units outstanding.

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 vested and issued under the LTIP	—
Balance at March 31, 2018	113,882,045

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 ended September 30, 2014.

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



	Amount per Common Unit		Declaration Date	Unitholder Record Date	Payment Date
Q4 2017	$	0.46	January 31, 2018	February 19, 2018	February 26, 2018

Cash distributions will be 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 each quarter will be determined by the board of directors of the General Partner following the end of such quarter. Available cash for each quarter will generally equal 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 General Partner deems necessary or appropriate, if any.

10. EARNINGS PER UNIT

The net income per common unit on the consolidated statements of operations is based on the net income of the Partnership for the three months ended March 31, 2018 and 2017, since this is the amount of net income that is attributable to the Partnership’s common units.

The Partnership’s net income is allocated wholly to the common units as the General Partner does not have an economic interest. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 9—Unitholders’ Equity and Partnership Distributions.

Basic net income per common unit is calculated by dividing net income 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.

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Viper Energy Partners LP

Notes to Financial Statements - (Continued)

(unaudited)



	Three Months Ended March 31,
	2018		2017
	(In thousands, except per unit amounts)
Net income attributable to the period	$	42,896	$	20,652
Weighted average common units outstanding
Basic weighted average common units outstanding	113,901		94,969
Effect of dilutive securities:
Potential common units issuable	90		10
Diluted weighted average common units outstanding	113,991		94,979
Net income per common unit, basic	$0.38		$0.22
Net income per common unit, diluted	$0.38		$0.22

For the three months ended March 31, 2018 and 2017, there were zero common units and 1,285,515 common units, respectively, that were not included in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per common unit in future periods.

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.

12. SUBSEQUENT EVENTS

Cash Distribution

On April 5, 2018, the board of directors of the General Partner approved a cash distribution for the first quarter of 2018 of $0.480 per common unit, payable on April 27, 2018, to unitholders of record at the close of business on April 20, 2018.

Proposed Tax Status Election and Related Transactions

On March 29, 2018, the Partnership announced that the Board of Directors of its 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 via a “check the box” election. In connection with making this election, the Partnership will (i) amend and restate its First Amended and Restated Partnership Agreement, (ii) amend and restate the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC (the “Operating Company”), (iii) amend and restate its existing registration rights agreement with Diamondback and (iv) enter into an exchange agreement with Diamondback, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback will deliver and assign to the Partnership the 73,150,000 Common Units it owns in exchange for (i) 73,150,000 newly-issued Class B Units of the Partnership and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018. The Partnership currently expects that the tax status election will be effective on May 10, 2018.

The Partnership’s Credit Facility

In connection with the Partnership’s spring 2018 redetermination, the agent lender under the credit agreement has recommended that the Partnership’s borrowing base be increased to $475.0 million. This increase is subject to approval of the required other lenders.

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ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017. 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 “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

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. The Partnership is currently focused on oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. As of March 31, 2018, our general partner held a 100% non-economic general partner interest in us, and Diamondback had an approximate 64% limited partner interest in us. 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 interests principally located in the Permian Basin of West Texas.

Sources of Our Income

Our income is 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 commodity prices, production mix and volumes of production sold by our operators.

The following table presents the breakdown of our operating income for the following periods:



	Three Months Ended March 31,
	2018		2017
Royalty income
Oil sales	89	%	86	%
Natural gas sales	4	%	4	%
Natural gas liquid sales	7	%	6	%
Lease bonus income	—	%	4	%
	100	%	100	%

As a result, our income is more sensitive to fluctuations in oil prices than is it 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 2017, West Texas Intermediate posted prices ranged from $42.48 to $60.46 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. During the first three months of 2018, West Texas Intermediate posted prices ranged from $59.20 to $66.27 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On March 29, 2018, the West Texas Intermediate posted price for crude oil was $64.87 per Bbl and the Henry Hub spot market price of natural gas was $2.81 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.

Recent Acquisitions

During the first quarter of 2018, we acquired 967 net royalty acres for an aggregate purchase price of $158.1 million, subject to post-closing adjustments, bringing our total mineral interests to 10,537 net royalty acres as of March 31, 2018.

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Production and Operational Update

Our average daily production during the first quarter of 2018 was 14,122 BOE/d (71% oil), and our operators received an average of $61.43 per Bbl of oil, $24.17 per Bbl of natural gas liquids and $2.22 per Mcf of natural gas, for an average realized price of $49.09 per BOE.

During the first quarter of 2018, the operators of our Spanish Trail mineral interests brought online 21 gross horizontal wells with an average royalty interest of 18.1%, consisting of nine Lower Spraberry, ten Wolfcamp A and two Wolfcamp B wells. As of March 31, 2018, there were 15 horizontal wells with an average royalty interest of 21.5% in various stages of drilling or completion on this acreage. 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 March 31, 2018, we had 793 vertical wells and 1,788 horizontal wells producing on our acreage. As of April 6, 2018, there were 24 active rigs and 825 active horizontal drilling permits on our acreage. We intend to continue to be active in acquiring mineral interests with near term visibility and accretive cash flow growth.

We declared a cash dividend for the first quarter of 2018 of $0.480 per common unit, payable on April 27, 2018, to unitholders of record at the close of business on April 20, 2018.

Proposed Tax Status Election and Related Transactions

On March 29, 2018, we announced that the Board of Directors of our general partner had 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 connection with making this election, we will (i) amend and restate our First Amended and Restated Partnership Agreement, (ii) amend and restate the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, or the Operating Company, (iii) amend and restate our existing registration rights agreement with Diamondback and (iv) enter into an exchange agreement with Diamondback, our general partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback will deliver and assign to us the 73,150,000 common units it owns 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. Immediately following that exchange, we will continue to be the managing member of the Operating Company, with sole control of its operations, and will own approximately 36% of the outstanding units issued by the Operating Company, and Diamondback will own 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 will be exchangeable from time to time for our common units (that is, one Operating Company unit and one Class B Viper unit, together, will be exchangeable for one Viper common unit). The general partner, a wholly-owned subsidiary of Diamondback, will continue to serve as our general partner. Accordingly, Diamondback will continue to control us and our financial results will continue to be consolidated with those of Diamondback. After the effectiveness of the tax status election and the completion of related transactions, our minerals business will continue to be conducted through the Operating Company, which will 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. We currently expect that the tax election will be effective on May 10, 2018. 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.

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 interests.

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,

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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.

In connection with the closing of the IPO, we and our general partner entered into an advisory services agreement with Wexford, pursuant to which Wexford provides general financial and strategic advisory services to us and our general partner in exchange for a $0.5 million annual fee and certain expense reimbursement.

Depletion

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 interests and major development projects for which proved reserves cannot yet be assigned, less accumulated depletion.

Income Tax Expense

We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income.

We are subject to the Texas margin tax. Diamondback does not expect any Texas margin tax to be due for the three months ended March 31, 2018 or 2017.

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Results of Operations

The following table summarizes our revenue and expenses and production data for the periods indicated.



	Three Months Ended March 31,
	2018			2017
	(unaudited, in thousands, except production data)
Operating Results:
Operating income:
Royalty income	$	62,393		$	32,050
Lease bonus income	—			1,602
Other operating income	50			—
Total operating income	62,443			33,652
Costs and expenses:
Production and ad valorem taxes	4,239			2,070
Gathering and transportation	265			143
Depletion	11,525			7,847
General and administrative expenses	2,711			2,142
Total costs and expenses	18,740			12,202
Income from operations	43,703			21,450
Other income (expense):
Interest expense, net	(2,098		)	(612		)
Gain on revaluation of investment	899			—
Other income (expense), net	392			(186		)
Total other expense, net	(807		)	(798		)
Net income	$	42,896		$	20,652

Production Data:
Oil (MBbls)	906			584
Natural gas (MMcf)	1,162			489
Natural gas liquids (MBbls)	171			101
Combined volumes (MBOE)	1,271			767
Daily combined volumes (BOE/d)	14,122			8,519
% Oil	71		%	76		%

Average sales prices:
Oil, realized ($/Bbl)	$	61.43		$	49.40
Natural gas realized ($/Mcf)	2.22			2.76
Natural gas liquids ($/Bbl)	24.17			18.34
Average price realized ($/BOE)	49.09			41.80

Average Costs ($/BOE)
Production and ad valorem taxes	$	3.34		$	2.70
Gathering and transportation expense	0.21			0.19
General and administrative - cash component	1.12			1.73
Total operating expense - cash	$	4.67		$	4.62

General and administrative - non-cash component	$	1.01		$	1.06
Interest expense	1.65			0.80
Depletion	9.07			10.24

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Comparison of the Three Months Ended March 31, 2018 and 2017

Royalty Income

Our royalty income for the three months ended March 31, 2018 and 2017 was $62.4 million and $32.1 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 three months ended March 31, 2018, we also benefited from a 65.8% increase in combined volumes sold by our operators as compared to the three months ended March 31, 2017.



	Change in prices			Production volumes⁽¹⁾		Total net dollar effect of change
						(in thousands)
Effect of changes in price:
Oil	$	12.03		906		$	10,906
Natural gas liquids	5.83			171		996
Natural gas	(0.54		)	1,162		(628		)
Total income due to change in price						$	11,274

	Change in production volumes⁽¹⁾			Prior period average prices		Total net dollar effect of change
						(in thousands)
Effect of changes in production volumes:
Oil	323			$	49.40	$	15,937
Natural gas liquids	69			18.34		1,273
Natural gas	674			2.76		1,859
Total income due to change in production volumes						19,069
Total change in income						$	30,343


(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 $1.6 million for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017. During the three months ended March 31, 2018, we did not receive any lease bonus payments. During the three months ended March 31, 2017, we received $1.6 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $2,489 per acre.

Other Operating Income

Other operating income was less than $0.1 million for the three months ended March 31, 2018 primarily related to surface damage payments. We did not receive any other operating income for the three months ended March 31, 2017.

General and Administrative Expenses

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 the three months ended March 31, 2018 and 2017, we incurred general and administrative expenses of $2.7 million and $2.1 million, respectively. The increase of $0.6 million during the three months ended March 31, 2018 was primarily due to an increase in unit-based compensation expense.

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Net Interest Expense

The net interest expense for the three months ended March 31, 2018 and 2017 reflects the interest incurred under our credit agreement. Net interest expense for the three months ended March 31, 2018 and 2017 was $2.1 million and $0.6 million, respectively. The increase of $1.5 million was due to a higher interest rate and increased borrowings during the three months ended March 31, 2018 as compared to the three months ended March 31, 2017.

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure 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 period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.

We define Adjusted EBITDA as net income plus interest expense, net, non-cash unit-based compensation expense, depletion expense and gain on revaluation of investment. Adjusted EBITDA is not a measure of net income as determined by GAAP. We exclude the items listed above from net income 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 historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, royalty income, cash flow from operating activities or any other measure of financial performance or liquidity presented 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.



	Three Months Ended March 31,
	2018			2017
	(In thousands)
Net income	$	42,896		$	20,652
Interest expense, net	2,098			612
Non-cash unit-based compensation expense	1,288			819
Depletion	11,525			7,847
Gain on revaluation of investment	(899		)	—
Adjusted EBITDA	$	56,908		$	29,930

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.

Our partnership agreement does not require us to distribute any of the cash we generate from operations. We believe, however, that it is in the best interests of our unitholders if we distribute a substantial portion of the cash we generate from operations. The board of directors of our general partner has adopted a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders.

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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 each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for each quarter generally equals 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. Following the effectiveness of our election to be treated as a taxable entity as discussed above, available cash for each quarter will also be reduced for cash needed for income taxes payable by us, if any.

Our Credit Agreement

On July 8, 2014, we entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended, 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 $400.0 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 November 1st. In addition, we may request up to three additional redeterminations of the borrowing base during any 12-month period. As of March 31, 2018, the borrowing base was set at $400.0 million, and we had $240.5 million of outstanding borrowings and $159.5 million available for future borrowings under our revolving credit facility. In connection with our spring 2018 redetermination, the agent lender under the credit agreement has recommended that our borrowing base be increased to $475.0 million. This increase is subject to approval of the required other lenders.

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.



Financial Covenant		Required Ratio
Ratio of total debt to EBITDAX		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

As of March 31, 2018, we were in compliance with the financial covenants under our 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

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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.



	Three Months Ended March 31,
	2018			2017

	(in thousands)
Cash Flow Data:
Net cash flows provided by operating activities	$	49,212		$	26,065
Net cash flows used in investing activities	(149,869		)	(8,579		)
Net cash flows provided by financing activities	94,611			1,864
Net (decrease) increase in cash	$	(6,046	)	$	19,350

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 $149.9 million and $8.6 million during the three months ended March 31, 2018 and 2017, respectively, and related to acquisitions of mineral interests.

Financing Activities

Net cash provided by financing activities was $94.6 million during the three months ended March 31, 2018, primarily related to proceeds from borrowings under our credit facility of $147.0 million, partially offset by distributions of $52.4 million to our unitholders during the period. Net cash provided by financing activities was $1.9 million during the three months ended March 31, 2017, primarily related to net proceeds of $147.5 million from our public offering of common units, substantially offset by the repayment of $120.5 million of net borrowings under our revolving credit agreement and distributions of $25.2 million to our unitholders during that period.

Contractual Obligations

There were no material changes in our contractual obligations and other commitments as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

Critical Accounting Policies

There have been no changes to our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

ITEM 3. 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

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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 two years, 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.

Credit Risk

We are subject to risk resulting from the concentration of royalty income in producing oil and natural gas interests and receivables with several significant purchasers. For the three months ended March 31, 2018, two purchasers each accounted for more than 10% of our royalty income: Shell Trading (US) Company (47%) and RSP Permian LLC (21%). For the three months ended March 31, 2017, two purchasers each accounted for more than 10% of our royalty income: Shell Trading (US) Company (59%) and RSP Permian LLC (19%). 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 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% in the case of the alternative base rate and from 1.75% to 2.75% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We entered into this credit agreement on July 8, 2014, as subsequently amended, and as of March 31, 2018, we had $240.5 million in outstanding borrowings. Our weighted average interest rate on borrowings under our revolving credit facility was 3.98%. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $2.4 million based on the $240.5 million outstanding in the aggregate under our credit agreement.

ITEM 4. 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 March 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 March 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 quarter ended March 31, 2018 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. 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 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.

In addition to the information set forth in this report, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10–K for the year ended December 31, 2017 and in subsequent filings we make with the SEC. There have been no material changes in our risk factors from those described in our Annual Report on Form 10–K for the year ended December 31, 2017.

ITEM 6. EXHIBITS



Exhibit Number	Description
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).
4.1	Registration Rights Agreement, dated June 23, 2014, 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 No. 001-36505) filed on June 23, 2014).
4.2	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).
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.
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 certifications attached as Exhibit 32.1 accompany this Quarterly Report on Form 10-Q 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 report to be signed on its behalf by the undersigned thereunto duly authorized.



		VIPER ENERGY PARTNERS LP

		By:	VIPER ENERGY PARTNERS GP LLC
			its General Partner

Date:	May 2, 2018	By:	/s/ Travis D. Stice
			Travis D. Stice
			Chief Executive Officer

Date:	May 2, 2018	By:	/s/ Teresa L. Dick
			Teresa L. Dick
			Chief Financial Officer