Edgar Filing: Viper Energy Partners LP

Document

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, 2019



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 Securities Exchange Act of 1934:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered	Units outstanding as of April 26, 2019
Common Units	VNOM	Nasdaq Global Select Market	62,628,357
Class B Units			72,418,500

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 every Interactive Data File required to be submitted 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 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	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. ¨

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

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VIPER ENERGY PARTNERS LP

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2019

TABLE OF CONTENTS



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

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

Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations	16

Item 3. Quantitative and Qualitative Disclosures about Market Risk	25

Item 4. Controls and Procedures	26

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	26

Item 1A. Risk Factors	26

Item 6. Exhibits	27

Signatures	28

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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.
Condensate	Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Crude oil	Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
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.
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.
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.
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.
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.

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WTI	West Texas Intermediate.

iii

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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.
Operating Company	Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy Partners LP.
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.
SEC	United States Securities and Exchange Commission.
Securities Act	The Securities Act of 1933, as amended.
Wells Fargo	Wells Fargo Bank, National Association.

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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,
	2019			2018

	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	10,133		$	22,676
Royalty income receivable	38,083			38,823
Royalty income receivable—related party	7,376			3,489
Other current assets	258			257
Total current assets	55,850			65,245
Property:
Oil and natural gas interests, full cost method of accounting ($916,437 and $871,485 excluded from depletion at March 31, 2019 and December 31, 2018, respectively)	1,798,679			1,716,713
Land	5,688			5,688
Accumulated depletion and impairment	(264,495		)	(248,296		)
Property, net	1,539,872			1,474,105
Other assets	21,257			17,831
Deferred tax asset	150,463			96,883
Total assets	$	1,767,442		$	1,654,064
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	8		$	—
Other accrued liabilities	2,772			6,022
Total current liabilities	2,780			6,022
Long-term debt	157,000			411,000
Total liabilities	159,780			417,022
Commitments and contingencies (Note 13)
Unitholders’ equity:
General partner	1,000			1,000
Common units (62,628,357 units issued and outstanding as of March 31, 2019 and 51,653,956 units issued and outstanding as of December 31, 2018)	817,014			540,112
Class B units (72,418,500 units issued and outstanding as of March 31, 2019 and as of December 31, 2018)	990			990
Total Viper Energy Partners LP unitholders’ equity	819,004			542,102
Non-controlling interest	788,658			694,940
Total equity	1,607,662			1,237,042
Total liabilities and unitholders’ equity	$	1,767,442		$	1,654,064

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,
	2019			2018
	(In thousands, except per unit amounts)
Operating income:
Royalty income	$	60,428		$	62,128
Lease bonus income	1,160			—
Other operating income	2			50
Total operating income	61,590			62,178
Costs and expenses:
Production and ad valorem taxes	3,692			4,239
Depletion	16,199			11,525
General and administrative expenses	1,695			2,711
Total costs and expenses	21,586			18,475
Income from operations	40,004			43,703
Other income (expense):
Interest expense, net	(4,549		)	(2,098		)
Gain on revaluation of investment	3,592			899
Other income, net	656			392
Total other income (expense), net	(301		)	(807		)
Income before income taxes	39,703			42,896
Benefit from income taxes	(34,608		)	—
Net income	74,311			42,896
Net income attributable to non-controlling interest	40,532			—
Net income attributable to Viper Energy Partners LP	$	33,779		$	42,896

Net income attributable to common limited partners per unit:
Basic	$	0.61		$	0.38
Diluted	$	0.61		$	0.38
Weighted average number of common limited partner units outstanding:
Basic	55,448			113,901
Diluted	55,475			113,991

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Unitholders' Equity

(Unaudited)



	Limited Partners								General Partner		Non-Controlling Interest
	Common					Class B			Amount		Amount
	Units		Amount			Units	Amount		Amount		Amount			Total
			(In thousands)
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-based compensation			1,288				—		—		—			1,288
Distributions to public			(18,737		)		—		—		—			(18,737		)
Distributions to Diamondback			(33,649		)		—		—		—			(33,649		)
Net income			42,896				—		—		—			42,896
Balance at March 31, 2018	113,882		$	887,055		—	$	—	$	—	$	—		$	887,055

Balance at December 31, 2018	51,654		$	540,112		72,419	$	990	$	1,000	$	694,940		$	1,237,042
Net proceeds from the issuance of common units - public	10,925		340,648				—		—		—			340,648
Unit-based compensation	60		405				—		—		—			405
Distributions to public			(25,970		)		—		—		—			(25,970		)
Distributions to Diamondback			(392		)		—		—		(36,934		)	(37,326		)
Distributions to General Partner			(20		)		—		—		—			(20		)
Change in ownership of consolidated subsidiaries, net			(71,195		)		—		—		90,120			18,925
Units repurchased for tax withholding	(11	)	(353		)		—		—		—			(353		)
Net income			33,779				—		—		40,532			74,311
Balance at March 31, 2019	62,628		$	817,014		72,419	$	990	$	1,000	$	788,658		$	1,607,662

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,
	2019			2018
	(In thousands)
Cash flows from operating activities:
Net income	$	74,311		$	42,896
Adjustments to reconcile net income to net cash provided by operating activities:
Benefit from deferred income taxes	(34,655		)	—
Depletion	16,199			11,525
Gain on revaluation of investment	(3,592		)	(899		)
Amortization of debt issuance costs	216			155
Non-cash unit-based compensation	405			1,288
Changes in operating assets and liabilities:
Royalty income receivable	740			(3,119		)
Royalty income receivable—related party	(3,887		)	(1,363		)
Accounts payable and other accrued liabilities	(3,289		)	(1,265		)
Income tax payable	47			—
Other current assets	(44		)	(6		)
Net cash provided by operating activities	46,451			49,212
Cash flows from investing activities:
Acquisition of oil and natural gas interests	(81,923		)	(149,994		)
Proceeds from the sale of investments	—			125
Net cash used in investing activities	(81,923		)	(149,869		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	59,500			147,000
Repayment on credit facility	(313,500		)	—
Debt issuance costs	(50		)	(3		)
Proceeds from public offerings	340,860			—
Public offering costs	(212		)	—
Units purchased for tax withholding	(353		)	—
Distributions to partners	(63,316		)	(52,386		)
Net cash provided by financing activities	22,929			94,611
Net decrease in cash	(12,543		)	(6,046		)
Cash and cash equivalents at beginning of period	22,676			24,197
Cash and cash equivalents at end of period	$	10,133		$	18,151

Supplemental disclosure of cash flow information:
Interest paid	$	4,908		$	2,072

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Condensed 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 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 the Partnership and its consolidated subsidiary, Viper Energy Partners LLC (the “Operating Company”).

As of March 31, 2019, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback had an approximate 54% limited partner interest in the Partnership. Diamondback owns and controls the General Partner.

Recapitalization, Tax Status Election and Related Transactions

In March 2018, the Board of Directors of the General Partner 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, on May 9, 2018 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 the 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 (the “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. Upon completion of the Partnership’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and Diamondback owned the remaining approximately 59%. 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 is anticipated to provide 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 GAAP. All material intercompany balances and transactions are eliminated in consolidation.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements

(Unaudited)

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, 2018, 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. See Note 12—Fair Value Measurements.

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 7. In addition to the 2018 tax year, the Partnership’s 2015 through 2017 tax years, periods during which the Partnership was organized as a pass-through entity for income tax purposes, remain open to examination by tax authorities. As of March 31, 2019, 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 three months ended March 31, 2019, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

New Accounting Pronouncements

Recently Adopted Pronouncements

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 is 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, 2019, 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 update effective January 1, 2019. It did not have a material 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 adopted this update effective January 1, 2019. It did not have a material impact 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. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact 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. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In January 2019, the Financial Accounting Standards Board issued Accounting Standards Update 2019-01, “Leases (Topic 842): Codification Improvements”. This update clarifies certain presentation and transition disclosures under Topic 842. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact 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. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact 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. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

Accounting Pronouncements Not Yet Adopted

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 April 2019, the Financial Accounting Standards Board issued Accounting Standards Update 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments”. This update clarifies guidance previously issued in ASU 2016-01, ASU 2016-13 and ASU 2017-12. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Partnership does not believe the updates to the referenced standards will have an impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. 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 prospectively. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

3. 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 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 or operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net 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 days’ production. Therefore, there are no remaining performance obligations under any of the Partnership’s royalty income contracts.

Contract balances

Under the Partnership’s royalty income contracts, it would have the right to receive royalty income 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.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

Prior-period performance obligations

The Partnership records revenue in the month production is delivered. 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, 2019, 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.

4. ACQUISITIONS

2019 Activity

During the three months ended March 31, 2019, the Partnership acquired from unrelated third parties mineral interests underlying 627 net royalty acres for an aggregate purchase price of approximately $82.7 million and, as of March 31, 2019, had mineral interests underlying 15,469 net royalty acres. The Partnership funded these acquisitions with cash on hand, a portion of the net proceeds from its February 2019 offering of common units and borrowings under its revolving credit facility.

2018 Activity

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,
	2019			2018

	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	882,242		$	845,228
Not subject to depletion	916,437			871,485
Gross oil and natural gas interests	1,798,679			1,716,713
Accumulated depletion and impairment	(264,495		)	(248,296		)
Oil and natural gas interests, net	1,534,184			1,468,417
Land	5,688			5,688
Property, net of accumulated depletion and impairment	$	1,539,872		$	1,474,105

Balance of acquisition costs not subject to depletion:
Incurred in 2019	$	70,766
Incurred in 2018	468,875
Incurred in 2017	284,371
Incurred in 2016	92,425
Total not subject to depletion	$	916,437

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

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 years 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 revenue including estimated expenditures (based on current costs) to be incurred in developing and producing the proved reserves, 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 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 the 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 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 Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of March 31, 2019, the borrowing base was set at $555.0 million, and there was $157.0 million of outstanding borrowings and $398.0 million available for future borrowings under the 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 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 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 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 of 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

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

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, 2019, the Operating Company was in compliance with the financial covenants under its credit agreement. The lenders may accelerate all of the indebtedness under the 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.

7. RELATED PARTY TRANSACTIONS

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 the three months ended March 31, 2019 and 2018, 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. For the three months ended March 31, 2019 and 2018, the Partnership did not pay any amounts under the Advisory Services Agreement. The Advisory Services Agreement was terminated on November 12, 2018; however, the Partnership’s payment obligation thereunder continues through the end of the current term in June 2019.

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 three months ended March 31, 2019, the Partnership accrued state income tax expense of $47,364 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 three months ended March 31, 2019, Diamondback paid the Partnership $198 in lease bonus payments to extend the term of one lease, reflecting an average bonus of $125 per acre and $3,101 in lease bonus payments for two new leases, reflecting an average bonus of $14,766 per acre. During the three months ended March 31, 2018, Diamondback did not pay the Partnership any lease bonus payments.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

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, 2019, a total of 8,943,806 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, 2019, the Partnership incurred $0.4 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, 2019:



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2018	125,053		$	23.44
Granted	11,001		$	33.30
Vested	(60,133	)	$	21.38
Unvested at March 31, 2019	75,921		$	26.51

The aggregate fair value of phantom units that vested during the three months ended March 31, 2019 was $1.3 million. As of March 31, 2019, the unrecognized compensation cost related to unvested phantom units was $1.5 million. Such cost is expected to be recognized over a weighted-average period of 0.99 years.

9. UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and limited partner units. At March 31, 2019, the Partnership had a total of 62,628,357 common units issued and outstanding and 72,418,500 Class B units outstanding, of which 731,500 common units and 72,418,500 Class B units were owned by Diamondback, representing approximately 54% 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, 2018	51,653,956
Common units issued in public offerings	10,925,000
Common units vested and issued under the LTIP	60,133
Units repurchased for tax withholding	(10,732	)
Balance at March 31, 2019	62,628,357

The Partnership had a total of 72,418,500 Class B units outstanding as of March 31, 2019 and December 31, 2018, respectively.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

In February 2019, the Partnership completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximately 54% of the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $340.6 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 outstanding borrowings under the revolving credit facility and finance acquisitions during the period.

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 2018	$	0.51	January 30, 2019	February 19, 2019	February 25, 2019

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, 2019 and 2018, 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. 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.



	Three Months Ended March 31,
	2019		2018
	(In thousands, except per unit amounts)
Net income attributable to the period	$	33,779	$	42,896
Weighted average common units outstanding:
Basic weighted average common units outstanding	55,448		113,901
Effect of dilutive securities:
Potential common units issuable	27		90
Diluted weighted average common units outstanding	55,475		113,991
Net income per common unit, basic	$	0.61	$	0.38
Net income per common unit, diluted	$	0.61	$	0.38

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

11. 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. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes for the period ended March 31, 2019 is based on the estimated annual effective tax rate plus discrete items.

The Partnership’s effective income tax rate was (87.17)% for the three months ended March 31, 2019. Total income tax benefit for the three months ended March 31, 2019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the revision of estimated deferred taxes recognized as a result of the Partnership’s change in tax status and net income attributable to the non-controlling interest.

For the three months ended March 31, 2019, the Partnership recorded a discrete income tax benefit of approximately $35.2 million related to the revision of estimated deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s federal 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. The Partnership prepared its best estimate of the resultant tax basis in the Operating Company for purposes of the Partnership’s income tax provision for the period of the change, but information necessary for the partnership to finalize its determination is not expected to be available until unitholders’ tax basis information is fully reported and the Partnership finalizes its federal income tax computations for 2018. Based on information available as of the balance sheet date, the Partnership has revised its estimate of the difference between its tax basis and its basis for financial accounting purposes in the Operating Company on the date of the tax status change, resulting in deferred income tax benefit of $35.2 million included in the Partnership’s income tax provision for the three months ended March 31, 2019.

Prior to May 10, 2018, the effective date of the Partnership’s change in income tax status, the Partnership was organized 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.

12. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Partnership’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Partnership uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(unaudited)

The Partnership’s cost method investment is reported at fair value on a recurring basis. The fair value of the Partnership’s investment at March 31, 2019 and December 31, 2018 was determined using the March 31, 2019 and December 31, 2018 quoted market prices. The investment is a Level 1 classification in the fair value hierarchy. See Note 2—Summary of Significant Accounting Policies. The following table summarizes the changes in fair value of the Partnership’s investment:



	(in thousands)
Fair Value of investment as of December 31, 2017	$	33,851
Impact of adoption of Accounting Standards Update 2016-01	(18,651		)
Gain on investment	899
Fair Value of investment as of March 31, 2018	$	16,099



	(in thousands)
Fair Value of investment as of December 31, 2018	$	14,525
Gain on investment	3,592
Fair Value of investment as of March 31, 2019	$	18,117

13. 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.

14. SUBSEQUENT EVENTS

Cash Distribution

On April 25, 2019, the board of directors of the General Partner approved a cash distribution for the first quarter of 2019 of $0.38 per common unit, payable on May 20, 2019, to unitholders of record at the close of business on May 13, 2019.

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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, 2018. 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. We are currently focused on oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. As of March 31, 2019, 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 54% 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 interests principally located in the Permian Basin of West Texas.

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 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,
	2019		2018
Operating income:
Royalty income
Oil sales	84	%	90	%
Natural gas sales	7	%	4	%
Natural gas liquid sales	7	%	6	%
Lease bonus income	2	%	—	%
	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 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. During the first three months of 2019, West Texas Intermediate posted prices ranged from $46.31 to $60.19 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.54 to $4.25 per MMBtu. On March 29, 2019, the West Texas Intermediate posted price for crude oil was $60.19 per Bbl and the Henry Hub spot market price of natural gas was $2.73 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 the credit agreement, which may be redetermined at the discretion of our lenders.

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Recent Acquisitions

During the three months ended March 31, 2019, we acquired from unrelated third parties 627 net royalty acres in 39 acquisitions for an aggregate purchase price of $82.7 million, subject to post-closing adjustments, bringing our total mineral interests to 15,469 net royalty acres as of March 31, 2019. We funded our acquisitions during the first quarter of 2019 with cash on hand, a portion of the net proceeds from our February 2019 equity offering and borrowings under our revolving credit facility.

Production and Operational Update

Our average daily production during the first quarter of 2019 was 19,042 BOE/d (67% oil), and our operators received an average of $45.31 per Bbl of oil, $18.09 per Bbl of natural gas liquids and $2.05 per Mcf of natural gas, for an average realized price of $35.26 per BOE.

During the first quarter of 2019, we were informed that 110 gross (1.8 net 100% royalty interest) horizontal wells with an average royalty interest of 1.6% had been turned to production on our existing acreage position. Of these 110 gross wells, Diamondback is the operator of 35 with an average royalty interest of 2.4%, and the remaining 75 gross wells, which have an average royalty interest of 1.3%, are operated by third parties. Additionally, during the first quarter of 2019, we acquired 627 net royalty acres which added a further 55 gross (2.0 net 100% royalty interest) producing horizontal wells with an average royalty interest of 3.6%. In total, as of March 31, 2019, we had 1,243 vertical wells and 2,604 horizontal wells producing on our acreage. There continues to be active development on our mineral acreage as represented by 38 active rigs on our acreage as of April 17, 2019 and 553 active drilling permits which had been filed in the past six months. We have an average 3.6% net royalty interest in approximately 113 gross wells we currently expect to be drilled by these 38 active rigs.

We declared a cash dividend for the first quarter of 2019 of $0.38 per common unit, payable on May 20, 2019, to unitholders of record at the close of business on May 13, 2019.

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 connection with making this 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 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. Upon completion of our July 2018 offering of 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. 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.

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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 natural 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, 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.

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

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.

We are subject to the Texas margin tax. For the three months ended March 31, 2019 and 2018, we accrued $47,364 and $0, respectively, for Texas margin tax payable pursuant to our tax sharing agreement with Diamondback.

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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,
	2019			2018
	(in thousands)
Operating Results:
Operating income:
Royalty income	$	60,428		$	62,128
Lease bonus income	1,160			—
Other operating income	2			50
Total operating income	61,590			62,178
Costs and expenses:
Production and ad valorem taxes	3,692			4,239
Depletion	16,199			11,525
General and administrative expenses	1,695			2,711
Total costs and expenses	21,586			18,475
Income from operations	40,004			43,703
Other income (expense):
Interest expense, net	(4,549		)	(2,098		)
Gain on revaluation of investment	3,592			899
Other income, net	656			392
Total other income (expense), net	(301		)	(807		)
Income before income taxes	39,703			42,896
Benefit from income taxes	(34,608		)	—
Net income	74,311			42,896
Net income attributable to non-controlling interest	40,532			—
Net income attributable to Viper Energy Partners LP	$	33,779		$	42,896

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	Three Months Ended March 31,
	2019			2018

Production Data:
Oil (MBbls)	1,147			906
Natural gas (MMcf)	1,872			1,162
Natural gas liquids (MBbls)	254			171
Combined volumes (MBOE)	1,714			1,271
Daily combined volumes (BOE/d)	19,042			14,122
% Oil	67		%	71		%

Average sales prices:
Oil ($/Bbl)	$	45.31		$	61.41
Natural gas ($/Mcf)	2.05			2.11
Natural gas liquids ($/Bbl)	18.09			23.47
Combined ($/BOE)	35.26			48.88

Average Costs ($/BOE):
Production and ad valorem taxes	$	2.15		$	3.34
General and administrative - cash component	0.75			1.12
Total operating expense - cash	$	2.90		$	4.46

General and administrative - non-cash component	$	0.24		$	1.01
Interest expense, net	2.65			1.65
Depletion	9.45			9.07

Comparison of the Three Months Ended March 31, 2019 and 2018

Royalty Income

Our royalty income for the three months ended March 31, 2019 and 2018 was $60.4 million and $62.1 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.

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The decrease in average prices received during the three months ended March 31, 2019 as compared to the three months ended March 31, 2018, was partially offset by a 34.8% increase in combined volumes sold by our operators as compared to the three months ended March 31, 2018.



	Change in prices			Production volumes⁽¹⁾		Total net dollar effect of change
						(in thousands)
Effect of changes in price:
Oil	$	(16.11	)	1,147		$	(18,483	)
Natural gas	$	(0.06	)	1,872		(107		)
Natural gas liquids	$	(5.37	)	254		(1,367		)
Total income due to change in price						$	(19,957	)

	Change in production volumes⁽¹⁾			Prior period average prices		Total net dollar effect of change
						(in thousands)
Effect of changes in production volumes:
Oil	241			$	61.41	$	14,800
Natural gas	709			$	2.11	1,495
Natural gas liquids	84			$	23.47	1,962
Total income due to change in production volumes						18,257
Total change in income						$	(1,700	)


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

Realized pricing is expected to improve beginning in the second quarter of 2019 as Diamondback’s fixed differential contracts roll off and convert to commitments on new-build long-haul pipelines or move closer to current Midland market price. Based on current market differentials and estimated in-basin gathering cost, we expect to realize approximately 88% to 92% of WTI in the future remainder of 2019 and approximately 100% of WTI in 2020.

Lease Bonus Income

Lease bonus income increased by $1.2 million for the three months ended March 31, 2019 as compared to the three months ended March 31, 2018. During the three months ended March 31, 2019, we received $44,688 in lease bonus payments to extend the term of five leases, reflecting an average bonus of $501 per acre and $1.1 million for six new leases, reflecting an average bonus of $16,674 per acre. During the three months ended March 31, 2018, we did not receive any lease bonus payments.

Depletion

Depletion expense increased by $4.7 million to $16.2 million for the three months ended March 31, 2019 from $11.5 million for the three months ended March 31, 2018. The increase resulted primarily from higher production levels and an increase in net book value on new reserves added.

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, 2019 and 2018, we incurred general and administrative expenses of $1.7 million and $2.7 million, respectively. The decrease of $1.0 million during the three months ended March 31, 2019 was primarily due to a decrease in unit-based compensation expense.

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Net Interest Expense

The net interest expense for the three months ended March 31, 2019 and 2018 reflects the interest incurred under our credit agreement. Net interest expense for the three months ended March 31, 2019 and 2018 was $4.5 million and $2.1 million, respectively. The increase of approximately $2.5 million was due to a higher interest rate and increased borrowings during the three months ended March 31, 2019 as compared to the three months ended March 31, 2018.

Benefit From Income Taxes

We recorded an income tax benefit of $34.6 million for the three months ended March 31, 2019. Prior to the second quarter of 2018, we had no provision for or benefit from income taxes. Total income tax benefit for the three months ended March 31, 2019 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and to discrete income tax benefit resulting from the revision of estimated deferred taxes recognized as a result of our change in tax status.

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 common unitholders.

We define Adjusted EBITDA as net income plus interest expense, net, non-cash unit-based compensation expense, depletion expense, gain on revaluation of investment and provision for (benefit from) income taxes. 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,
	2019			2018
	(In thousands)
Net income	$	74,311		$	42,896
Interest expense, net	4,549			2,098
Non-cash unit-based compensation expense	405			1,288
Depletion	16,199			11,525
Gain on revaluation of investment	(3,592		)	(899		)
Benefit from income taxes	(34,608		)	—
Consolidated Adjusted EBITDA	57,264			56,908
EBITDA attributable to non-controlling interest	(30,708		)	—
Adjusted EBITDA attributable to Viper Energy Partners LP	$	26,556		$	56,908

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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, issuance of common units to the sellers 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. However, 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 its unitholders (including us), and we, in turn, will distribute all of the available cash we receive from the Operating Company to our common unitholders.

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

February 2019 Equity Offering

In February 2019, we completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximately 54% of our total units then outstanding. We received net proceeds from this offering of approximately $340.6 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 outstanding borrowings under the revolving credit facility and finance acquisitions during the period.

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 the 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 November 1st. 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 March 31, 2019, the borrowing base was set at $555.0 million, and we had $157.0 million of outstanding borrowings and $398.0 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

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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 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

As of March 31, 2019, the Operating Company was in compliance with the 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:



	Three Months Ended March 31,
	2019			2018

	(in thousands)
Cash Flow Data:
Net cash flows provided by operating activities	$	46,451		$	49,212
Net cash flows used in investing activities	(81,923		)	(149,869		)
Net cash flows provided by financing activities	22,929			94,611
Net decrease in cash	$	(12,543	)	$	(6,046	)

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 $81.9 million and $149.9 million during the three months ended March 31, 2019 and 2018, respectively, and related to acquisitions of oil and natural gas interests and land.

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Financing Activities

Net cash provided by financing activities was $22.9 million during the three months ended March 31, 2019, primarily related to net proceeds from our public offering of common units of $340.6 million and payments from net borrowings under our credit facility of $254.0 million, partially offset by distributions of $63.3 million to our unitholders during the period. 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 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, 2018.

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, 2018.

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 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, 2019, three purchasers each accounted for more than 10% of our royalty income: Trafigura Trading LLC (38%), Concho Resources, Inc. (13%) and Shell Trading (US) Company (11%). 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%). 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, 2019, we had $157.0 million in outstanding borrowings. Our weighted average interest rate on borrowings under our revolving credit facility

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was 4.49%. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $1.6 million based on the $157.0 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, 2019, 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, 2019, 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, 2019 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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, 2018 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, 2018.

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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	Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 9, 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).
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 Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of May 9, 2018. (incorporated by reference to Exhibit 3.3 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).
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. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL 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 1, 2019	By:	/s/ Travis D. Stice
			Travis D. Stice
			Chief Executive Officer

Date:	May 1, 2019	By:	/s/ Teresa L. Dick
			Teresa L. Dick
			Chief Financial Officer