Cover - USD ($) $ in Billions	12 Months Ended
Cover - USD ($) $ in Billions	Dec. 31, 2019	Feb. 07, 2020	Jun. 28, 2019	Dec. 31, 2018
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-36505
Entity Registrant Name	Viper Energy Partners LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-5001985
Entity Address, Address Line One	500 West Texas
Entity Address, Address Line Two	Suite 1200
Entity Address, City or Town	Midland,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	79701
City Area Code	432
Local Phone Number	221-7400
Title of 12(b) Security	Common Units
Trading Symbol	VNOM
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 1.9
Entity Common Units, Units Outstanding		67,805,707
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0001602065
Current Fiscal Year End Date	--12-31
Class B Units
Entity Information [Line Items]
Limited partners' capital account, units outstanding	90,709,946	90,709,946		72,418,500

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 3,602	$ 22,676
Royalty income receivable	58,089	38,823
Royalty income receivable—related party	10,576	3,489
Other current assets	397	257
Total current assets	72,664	65,245
Property:
Oil and natural gas interests, full cost method of accounting ($1,551,767 and $871,485 excluded from depletion at December 31, 2019 and December 31, 2018, respectively)	2,868,459	1,716,713
Land	5,688	5,688
Accumulated depletion and impairment	(326,474)	(248,296)
Property, net	2,547,673	1,474,105
Deferred tax asset	142,466	96,883
Other assets	22,823	17,831
Total assets	2,785,626	1,654,064
Current liabilities:
Accounts payable—related party	150	0
Accrued liabilities	13,282	6,022
Total current liabilities	13,432	6,022
Long-term debt, net	586,774	411,000
Total liabilities	600,206	417,022
Commitments and contingencies (Note 12)
Unitholders’ equity:
General partner	889	1,000
Common units (67,805,707 units issued and outstanding as of December 31, 2019 and 51,653,956 units issued and outstanding as of December 31, 2018)	929,116	540,112
Class B units (90,709,946 units issued and outstanding as of December 31, 2019 and 72,418,500 units issued and outstanding December 31, 2018)	1,130	990
Total Viper Energy Partners LP unitholders’ equity	931,135	542,102
Non-controlling interest	1,254,285	694,940
Total equity	2,185,420	1,237,042
Total liabilities and unitholders’ equity	$ 2,785,626	$ 1,654,064

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating income:
Royalty income	$ 293,811	$ 282,661	$ 160,163
Lease bonus income	4,117	6,029	11,870
Other operating income	355	130	0
Total operating income	298,283	288,820	172,033
Costs and expenses:
Production and ad valorem taxes	19,076	19,048	10,608
Gathering and transportation	0	0	789
Depletion	78,178	58,830	40,519
General and administrative expenses	7,489	7,955	6,296
Total costs and expenses	104,743	85,833	58,212
Income from operations	193,540	202,987	113,821
Other income (expense):
Interest expense, net	(21,076)	(13,849)	(3,164)
Gain (loss) on revaluation of investment	4,832	(550)	0
Other income, net	2,332	1,924	821
Total other expense, net	(13,912)	(12,475)	(2,343)
Income before income taxes	179,628	190,512	111,478
Benefit from income taxes	(41,582)	(72,365)	0
Net income	221,210	262,877	111,478
Net income attributable to non-controlling interest	174,929	118,919	0
Net income attributable to Viper Energy Partners LP	$ 46,281	$ 143,958	$ 111,478
Net income attributable to common limited partner units:
Basic (dollars per shares)	$ 0.75	$ 2.01	$ 1.07
Diluted (dollars per shares)	$ 0.75	$ 2.01	$ 1.07
Weighted average number of common limited partner units outstanding:
Basic (in shares)	61,744	71,546	104,318
Diluted (in shares)	61,787	71,626	104,383

Statement of Consolidated Unitholders' Equity and Members' Equity - USD ($) $ in Thousands	Total	General Partner	Non-Controlling Interest	Common Units	Common Units Limited Partners	Class B Units	Class B Units Limited Partners	Class B Units Non-Controlling Interest
Beginning balance (in shares) at Dec. 31, 2016					87,800,000		0
Beginning balance at Dec. 31, 2016	$ 547,898	$ 0	$ 0		$ 547,898		$ 0
Increase (Decrease) in Partners' Capital [Roll Forward]
Net proceeds from the issuance of common units - public (in shares)					25,175,000
Net proceeds from the issuance of common units - public	369,896				$ 369,896
Net proceeds from the issuance of common units - Diamondback (in shares)					700,000
Net proceeds from the issuance of common units - Diamondback	10,067				$ 10,067
Units issued for acquisition (in shares)					175,000
Units issued for acquisition	3,050				$ 3,050
Unit-based compensation (in shares)					32,000
Unit-based compensation	2,395				$ 2,395
Distributions to public	(41,367)				(41,367)
Distributions to Diamondback	(89,509)				(89,509)
Net income	111,478				$ 111,478
Ending balance (in shares) at Dec. 31, 2017					113,882,000		0
Ending balance at Dec. 31, 2017	913,908	0	0		$ 913,908		$ 0
Increase (Decrease) in Partners' Capital [Roll Forward]
Unit exchange related to tax conversion (in shares)					(73,150,000)		73,150,000
Unit exchange related to tax conversion	2,000	1,000	545,441		$ (545,441)		$ 1,000
Recapitalization related to tax conversion (in shares)					732,000		(732,000)
Recapitalization related to tax conversion	(10)						$ (10)
Net proceeds from the issuance of common units - public (in shares)					10,080,000
Net proceeds from the issuance of common units - public	303,121				$ 303,121
Unit-based compensation (in shares)					103,000
Unit-based compensation	2,763				$ 2,763
Unit options exercised (in shares)					8,000
Unit options exercised	140				$ 140
Distributions to public	(98,333)				(98,333)
Distributions to Diamondback	(155,109)		(85,454)		(69,655)
Distributions to General Partner	(31)				(31)
Change in ownership of consolidated subsidiaries, net	24,367		116,034		(91,667)
Net income	262,877		118,919		$ 143,958
Ending balance (in shares) at Dec. 31, 2018					51,654,000		72,419,000
Ending balance at Dec. 31, 2018	1,237,042	1,000	694,940		$ 540,112		$ 990
Increase (Decrease) in Partners' Capital [Roll Forward]
Net proceeds from the issuance of common units - public (in shares)				10,925,000	10,925,000
Net proceeds from the issuance of common units - public	340,860				$ 340,860
Units issued for acquisition (in shares)				5,152,124	5,152,000		18,291,000
Units issued for acquisition	124,012				$ 124,012	$ 497,412	$ 250	$ 497,162
Offering costs	(221)				$ (221)
Unit-based compensation (in shares)				85,359	85,000
Unit-based compensation	1,822				$ 1,822
Distributions to public	(107,074)				(107,074)
Distributions to Diamondback	(133,211)		(131,801)		(1,300)		$ (110)
Distributions to General Partner	(80)	(111)			31
Change in ownership of consolidated subsidiaries, net	4,001		19,055		$ (15,054)
Units repurchased for tax withholding (in shares)				(10,732)	(11,000)
Units repurchased for tax withholding	(353)				$ (353)
Net income	221,210		174,929		$ 46,281
Ending balance (in shares) at Dec. 31, 2019					67,806,000		90,710,000
Ending balance at Dec. 31, 2019	$ 2,185,420	$ 889	$ 1,254,285		$ 929,116		$ 1,130

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income	$ 221,210	$ 262,877	$ 111,478
Adjustments to reconcile net income to net cash provided by operating activities:
Benefit from deferred income taxes	(41,582)	(72,516)	0
Depletion	78,178	58,830	40,519
(Gain) loss on revaluation of investment	(4,832)	550	0
Amortization of debt issuance costs	978	737	589
Non-cash unit-based compensation	1,822	2,763	2,395
Changes in operating assets and liabilities:
Restricted cash			500
Royalty income receivable	(19,266)	(13,069)	(15,711)
Royalty income receivable—related party	(7,087)	1,653	(1,672)
Accounts payable and accrued liabilities	7,091	2,545	1,298
Accounts payable—related party	150	0	0
Income tax payable	169	151	0
Other current assets	(140)	(28)	(177)
Net cash provided by operating activities	236,691	244,493	139,219
Cash flows from investing activities:
Acquisition of oil and natural gas interests	(530,572)	(610,131)	(344,079)
Acquisition of land	0	(4,687)	0
Proceeds from sale of assets	0	441	0
Proceeds from the sale of investments	0	124	0
Net cash used in investing activities	(530,572)	(614,253)	(344,079)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	590,500	691,500	278,500
Repayment on credit facility	(905,000)	(374,000)	(305,500)
Proceeds from senior notes	500,000	0	0
Debt issuance costs	(10,863)	(1,039)	(2,259)
Proceeds from public offerings	340,860	305,773	380,412
Public offering costs	(221)	(2,652)	(433)
Units purchased for tax withholding	(353)	0	0
Proceeds from exercise of unit options	0	140	0
Contributions by members	250	2,000	0
Distributions to partners	(240,366)	(253,483)	(130,876)
Net cash provided by financing activities	274,807	368,239	219,844
Net (decrease) increase in cash	(19,074)	(1,521)	14,984
Cash and cash equivalents at beginning of period	22,676	24,197	9,213
Cash and cash equivalents at end of period	3,602	22,676	24,197
Supplemental disclosure of cash flow information:
Interest paid	13,803	12,438	2,589
Supplemental disclosure of non—cash transactions:
OpCo units issued for the Drop-Down transaction (Note 3)	497,162	0	0
Common units issued for acquisition	$ 124,012	$ 0	$ 3,050

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Presentation	ORGANIZATION AND BASIS OF PRESENTATION Organization Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”), on February 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin and Eagle Ford Shale. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of Viper Energy Partners LP and its consolidated subsidiary, Viper Energy Partners LLC. As of December 31, 2019, a wholly-owned subsidiary of Diamondback, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback had an approximate 58% 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 was adopted to provide anticipated significant benefits to the Partnership’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018. Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

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

Cash and Cash Equivalents

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

Accrued Liabilities

Accrued liabilities consist of the following:



	December 31,
	2019		2018
	(In thousands)
Interest payable	$	6,718	$	728
Ad valorem taxes payable	5,632		5,039
Other	932		255
Total accrued liabilities	$	13,282	$	6,022

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 pricing provisions in the Partnership’s contracts are tied to a market index.

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

The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers

to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

Transaction price allocated to remaining performance obligations

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

Contract balances

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

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 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.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, receivables, payables, a cost method investment, a credit agreement, and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the cost method investment is determined using the quoted market prices for those periods. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Partnership for bank loans with similar terms and maturities. The fair value of the senior notes are determined using quoted market prices.

Oil and Natural Gas Properties

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $9.95, $9.33 and $10.07 for the years ended December 31, 2019, 2018 and 2017, respectively. Depletion for oil and natural gas properties was $78.2 million, $58.8 million and $40.5 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2019, 2018 and 2017.

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

Debt Issuance Costs

Other assets include capitalized costs related to the credit facility of $6.6 million, $5.5 million and $4.4 million, net of accumulated amortization of $3.1 million, $2.2 million and $1.4 million as of December 31, 2019, 2018 and 2017, respectively. The costs are associated with the Partnership’s credit agreement and are being amortized over the term of the credit agreement.

Long-term debt included capitalized costs related to the senior notes of $2.5 million, net of accumulated amortization of $0.05 million, as of December 31, 2019. There were no capitalized costs or accumulated amortization related to senior notes as of December 31, 2018 or 2017. The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using the effective interest method.

Concentrations

The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2019, three purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (27%), Concho Resources, Inc. (16%) and Shell Trading (US) Company (“Shell Trading”) (12%). For the year ended December 31, 2018, three purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (31%), Concho Resources, Inc. (16%) and Trafigura Trading LLC (11%). For the year ended December 31, 2017, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (47%) and RSP Permian LLC (23%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Earnings Per Unit

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

Unit–Based Compensation

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

Income Taxes

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

The Partnership is subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 10—Income Taxes. In addition to the 2019 and 2018 tax years, the Partnership’s 2016 and 2017 tax years, during which the Partnership was organized as a pass-through entity for federal income tax purposes, remain open to examination by tax authorities. As of December 31, 2019 and 2018, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2019, 2018 and 2017, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.

For the year ended December 31, 2019, the Partnership did not accrue any state income tax expense. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million, for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback. For the year ended December 31, 2017, no amount of Texas margin tax has been provided in the accompanying financial statements.

Recent Accounting Pronouncements

The Partnership considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Partnership’s analysis of the effects on its financial statements:



Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”	This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.	Q1 2020	The Partnership adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”	This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions	ACQUISITIONS 2019 Activity Drop-Down Acquisition On October 1, 2019, we completed the acquisition of certain mineral and royalty interests from subsidiaries of Diamondback for approximately 18.3 million of its newly-issued Class B units, approximately 18.3 million newly-issued units of the Operating Company with a fair value of $497.2 million and $190.2 million in cash, after giving effect to closing adjustments for net title benefits (the ‘‘Drop-Down Acquisition’’). The mineral and royalty interests acquired in the Drop-Down Acquisition represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by Diamondback, and have an average net royalty interest of approximately 3.2% (the ‘‘Drop-Down Assets’’). The Partnership completed the acquisition on October 1, 2019 and funded the cash portion of the purchase price for the Drop-Down Assets through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. In connection with the closing of the Drop-Down Acquisition, the borrowing base under the Operating Company’s revolving credit facility was increased by $125.0 million to $725.0 million from $600.0 million. Santa Elena Acquisition On October 31, 2019, the Partnership completed the acquisition of certain mineral and royalty interests from Santa Elena (the ‘‘Santa Elena Acquisition’’), which assets were immediately contributed by the Partnership to the Operating Company. The assets acquired in the Santa Elena Acquisition represent approximately 1,366 net royalty acres across the Midland Basin with an average net royalty interest of approximately 5.6% and are primarily operated by Diamondback in Glasscock and Martin counties (the ‘‘Santa Elena Assets’’). At closing, the Partnership issued to Santa Elena approximately 5.2 million common units representing limited partner interests in the Partnership as consideration for the Santa Elena Assets, and the Operating Company issued to the Partnership approximately 5.2 million new units of the Operating Company with a fair value of $124.0 million. Other Recent Acquisitions In addition, during the year ended December 31, 2019, the Partnership acquired, from unrelated third-party sellers, mineral interests representing 136,012 gross (2,607 net royalty) acres for an aggregate of approximately $343.7 million. The Partnership funded these acquisitions with cash on hand, a portion of the net proceeds from its first quarter 2019 offering of common units and borrowings under the Operating Company’s revolving credit facility. As a result of the Drop-Down Acquisition, the Santa Elena Acquisition and the other recently completed acquisitions described above, as of December 31, 2019, the Partnership’s assets included mineral interests representing 814,224 gross (24,304 net royalty) acres in the Permian Basin and the Eagle Ford Shale, approximately 50% of which are operated by Diamondback. 2018 Activity During the year ended December 31, 2018, the Partnership acquired mineral interests from unrelated third parties underlying 3,585 net royalty acres for an aggregate of approximately $440.4 million and, as of December 31, 2018, had mineral interests underlying 14,841 net royalty acres. The Partnership funded these acquisitions primarily with cash on hand and borrowings under its revolving credit facility. On August 15, 2018, the Partnership acquired mineral interests from Diamondback underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by Diamondback, for $175.0 million. 2017 Activity During the year ended December 31, 2017, the Partnership acquired mineral interests underlying 3,157 net royalty acres for an aggregate of approximately $343.1 million and, as of December 31, 2017, had mineral interests underlying 9,570 net royalty acres. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility, with portion of the net proceeds from its January and July 2017 offerings of common units and with the issuance of 174,513 common units to a seller in a private placement in May 2017.

Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Debt

DEBT



	December 31,
	2019			2018
	(in thousands)
5.375 % Senior Notes due 2027	$	500,000		$	—
Revolving credit facility	96,500			411,000
Unamortized debt issuance costs	(2,458		)	—
Unamortized discount costs	(7,268		)	—
Total long-term debt	$	586,774		$	411,000

2027 Senior Notes

On October 16, 2019, the Partnership completed an offering (the “Notes Offering”) of $500.0 million in aggregate principal amount of its 5.375% Senior Notes due 2027 (the “Notes”). The Partnership received net proceeds of approximately $490.0 million from the Notes Offering. The Partnership loaned the gross proceeds to the Operating Company. The Operating Company used the proceeds from the Notes Offering to pay down borrowings under its revolving credit facility.

The Notes are senior unsecured obligations of the Partnership, initially are guaranteed on a senior unsecured basis by the Operating Company, and will pay interest semi-annually. Neither Diamondback nor the general partner will guarantee the Notes. In the future, each of the Partnership’s restricted subsidiaries that either (1) guarantees any of its or a guarantor’s other indebtedness or (2) is a domestic restricted subsidiary and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Notes.

Intercompany Promissory Note

In connection with and upon closing of the Notes Offering, the Partnership loaned the gross proceeds from the Notes Offering to the Operating Company under the terms of that certain Subordinated Promissory Note, dated as of October 16, 2019, by the Operating Company in favor of the Partnership (the “Intercompany Promissory Note”). The Intercompany Promissory Note requires the Operating Company to repay the underlying loan to the Partnership on the same terms and in the same amounts as the Notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. The Partnership’s right to receive payment under the Intercompany Promissory Note is contractually subordinated to the Operating Company’s guarantee of the notes and is structurally subordinated to all of the Operating Company’s secured indebtedness (including all borrowings and other obligations under the Operating Company’s revolving credit facility) to the extent of the value of the collateral securing such indebtedness.

The Operating Company’s Revolving Credit Facility

On July 20, 2018, the Partnership, as guarantor, entered into an amended and restated credit agreement with the Operating Company, as borrower, Wells Fargo National Bank (“Wells Fargo”), as administrative agent, and the other lenders. The credit agreement, as amended to the date hereof, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on the Operating Company’s oil and natural gas reserves and other factors (the ‘‘borrowing base’’) of $775.0 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. Upon closing of the Drop-Down Acquisition on October 1, 2019, the borrowing base under the Operating Company’s revolving credit facility was increased by $125.0 million to $725.0 million from $600.0 million. Effective October 8, 2019, in connection with the commencement of the Notes Offering described above, the Partnership entered into a third amendment to the Operating Company’s revolving credit facility, which provided for the waiver of the automatic reduction of the borrowing base that would have otherwise occurred upon the consummation of the Notes Offering. In addition, the third amendment increased the maximum amount of unsecured senior or senior subordinated notes that may be issued by the Operating Company or the Partnership from $400.0 million to $1.0 billion.

The Partnership funded the cash portion of the purchase price for the Drop-Down Acquisition through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. The Operating Company used the proceeds from the Notes Offering to pay down borrowings under its revolving credit facility. Additionally, in connection with the Partnership’s fall redetermination in November 2019, the borrowing base under the Operating Company’s revolving credit facility was increased to $775.0 million. As of December 31, 2019, the borrowing base was set at $775.0 million, and the Partnership had $96.5 million of outstanding borrowings and $678.5 million available for future borrowings under its revolving credit facility.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the 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 the loans outstanding in relation to the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all the assets of the Partnership and the Operating Company.

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



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

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $1.0 billion in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

As of December 31, 2019, the Operating Company was in compliance with all financial covenants under its credit agreement. The lenders may accelerate all of the indebtedness under the Operating Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS Acquisition On October 1, 2019, the Partnership completed the acquisition from Diamondback of certain mineral and royalty interests across the Midland and Delaware Basins on a transaction valued at $687.4 million. For additional information regarding this acquisition, see Note 3—Acquisitions. On August 15, 2018, the Partnership acquired from Diamondback mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by Diamondback, for $175.0 million. Partnership Agreement The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Partnership Agreement”), requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For the year ended December 31, 2019, the General Partner allocated $3.1 million, to the Partnership. For each of the years ended December 31, 2018 and 2017, the General Partner allocated $2.5 million, to the Partnership. Advisory Services Agreement In connection with the closing of the IPO, the Partnership and the General Partner entered into an advisory services agreement with Wexford Capital LP (“Wexford”) dated as of June 23, 2014 (the “Advisory Services Agreement”), under which Wexford agreed to provide the Partnership and the General Partner with general financial and strategic advisory services related to the Partnership’s business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement was terminated on November 12, 2018 with an effective date of December 31, 2018. For the years ended December 31, 2019, 2018 and 2017, the Partnership did not pay any amounts under the Advisory Services Agreement. Tax Sharing In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2019, the Partnership did not accrue any state income tax expense. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million, for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback. Lease Bonus During the year ended December 31, 2019, Diamondback paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases and $0.2 million in lease bonus payments for four new leases. During the year ended December 31, 2018, Diamondback paid the Partnership $2.5 million in lease bonus payments to extend the term of 13 leases and $0.6 million in lease bonus payments for one new lease. During the year ended December 31, 2017, Diamondback paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases.

Unitholders’ Equity and Partnership Distributions

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Unitholders’ Equity and Partnership Distributions

UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and limited partner units. At December 31, 2019, the Partnership had a total of 67,805,707 common units and 90,709,946 Class B units issued and outstanding, of which 731,500 common units and 90,709,946 Class B units were owned by Diamondback, representing approximately 58% 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	85,359
Units repurchased for tax withholding	(10,732	)
Common units issued for acquisition	5,152,124
Balance at December 31, 2019	67,805,707

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



	Class B Units
Balance at December 31, 2018	72,418,500
Units issued for the Drop-Down	18,291,446
Balance at December 31, 2019	90,709,946

In March 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 Operating Company’s revolving credit facility and finance acquisitions during the period.

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

In connection with the IPO, the board of directors of the General Partner adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis.

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



Declaration Date	Quarter	Amount per Common Unit		Payment Date	Amount Distributed to Diamondback
					(in thousands)
April 28, 2017	Q1 2017	$	0.302	May 25, 2017	$	21,880
July 28, 2017	Q2 2017	$	0.332	August 24, 2017	$	24,286
October 16, 2017	Q3 2017	$	0.337	November 14, 2017	$	24,652
January 31, 2018	Q4 2017	$	0.460	February 26, 2018	$	33,649
April 5, 2018	Q1 2018	$	0.480	April 27, 2018	$	35,112
July 27, 2018	Q2 2018	$	0.600	August 20, 2018	$	43,901
October 23, 2018	Q3 2018	$	0.580	November 19, 2018	$	42,447
January 30, 2019	Q4 2018	$	0.510	February 25, 2019	$	37,326
April 25, 2019	Q1 2019	$	0.380	May 20, 2019	$	27,817
July 28, 2019	Q2 2019	$	0.470	August 21, 2019	$	34,400
October 25, 2019	Q3 2019	$	0.460	November 15, 2019	$	33,668

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

Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

As discussed further in Note 1—Organization and Basis of Presentation, on March 29, 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. Because the operations of the business continue to be conducted through a pass-through entity, the Operating Company, in which the Partnership and Diamondback have ownership, represents a continuation of the historic pass-through entity for federal income tax purposes. Notwithstanding this federal income tax treatment, the change in the Partnership’s tax status is accounted for under financial accounting rules as a change in the Partnership’s tax status. This accounting treatment results in the Partnership’s financial statements for the year ended December 31, 2018 reflecting an estimated deferred tax benefit attributable to the Partnership succeeding to the tax basis of the Partnership’s unitholders in the unitholders’ Partnership units as of the effective date of the conversion, and deferred tax benefit related to revision of this estimate for the year ended December 31, 2019.

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

The Partnership’s effective income tax rates were (23.1)% and (38.0)% for the years ended December 31, 2019 and 2018, respectively. Total income tax benefit for the year ended December 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 net income attributable to the non-controlling interest and the revision of estimated deferred taxes recognized as a result of the Partnership’s change in tax status. Total income tax benefit for the year ended December 31, 2018 differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to (i) net income attributable to the non-controlling interest, (ii) net income attributable to the period prior to the Partnership’s change in tax status, and (iii) the impact of deferred taxes recognized as a result of the Partnership’s change in tax status.

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

The components of the provision for income taxes for the years ended December 31, 2019 and 2018 are as follows:



	Year Ended December 31,
	2019			2018
	(In thousands)
Current income tax provision (benefit):
Federal	$	—		$	—
State	—			151
Total current income tax provision	—			151
Deferred income tax provision (benefit):
Federal	(41,582		)	(72,516		)
State	—			—
Total deferred income tax provision (benefit)	(41,582		)	(72,516		)
Total benefit from income taxes	$	(41,582	)	$	(72,365	)

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



	Year Ended December 31,
	2019			2018
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	37,722		$	40,008
Impact of net income attributable to the pre-incorporation period	—			(14,279		)
Impact of nontaxable noncontrolling interest	(36,735		)	(24,973		)
State income tax expense (benefit), net of federal tax effect	—			119
Deferred taxes related to change in tax status	(42,424		)	(72,787		)
Other, net	(145		)	(453		)
Provision for (benefit from) income taxes	$	(41,582	)	$	(72,365	)

The components of the Company’s deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows:



	Year Ended December 31,
	2019			2018
	(In thousands)
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$	7,958		$	2,131
Investment in the Operating Company	134,272			94,468
Other	237			284
Total deferred tax assets	142,467			96,883
Valuation allowance	(1		)	—
Net deferred tax assets	142,466			96,883
Deferred tax liabilities:
Oil and natural gas properties and equipment	—			—
Other	—			—
Total deferred tax liabilities	—			—
Net deferred tax assets (liabilities)	$	142,466		$	96,883

As of December 31, 2019 and 2018, the Partnership had net deferred tax assets of approximately $142.5 million and $96.9 million, respectively. 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 consisted 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 was not available until unitholders’ tax basis information was fully reported and the Partnership finalized its federal income tax computations for 2018. Based on such finalized information as of the third quarter 2019, the Partnership 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 $42.4 million included in the Partnership’s income tax provision for the year ended December 31, 2019. At December 31, 2019, the Partnership has federal net operating loss carryforwards of approximately $37.9 million which may be carried forward indefinitely to offset future taxable income.

Management considers the likelihood that the Partnership’s net operating losses and other deferred tax attributes will be utilized prior to their expiration, if applicable. At December 31, 2019, management’s assessment included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities and projected future taxable income. As a result of the assessment, a valuation allowance was recorded at December 31, 2019 related to state net operating loss carryforwards not anticipated to be utilized prior to expiration. Management determined that it is more likely than not that the Partnership will realize its remaining deferred tax assets.

The Partnership principally operates in the state of Texas. For the year ended December 31, 2019, the Partnership did not accrue any state income tax expenses. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million, for its share of Texas margin tax attributable to the Partnership’s results which are included in a combined tax return filed by Diamondback. At December 31, 2019, the Partnership did not have any significant uncertain tax positions requiring recognition in the financial statements. In addition to the 2019 and 2018 tax years, our 2016 and 2017 tax years, periods during which we were organized as a pass-through entity for income tax purposes, remain open to examination by tax authorities.

Fair Value Measurements

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

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

The Partnership’s cost method investment is reported at fair value on a recurring basis. The fair value of the Partnership’s investment at December 31, 2019, 2018 and 2017 was determined using the quoted market prices for those periods. The investment is a Level 1 classification in the fair value hierarchy. The following table summarizes the changes in fair value of the Partnership’s investment:



	(in thousands)
Fair value of investment as of December 31, 2018	$	14,525
Gain on investment	4,832
Fair value of investment as of December 31, 2019	$	19,357



	(in thousands)
Fair value of investment as of December 31, 2017	$	33,851
Impact of adoption of Accounting Standards Update 2016-01	(18,651		)
Disposal of shares	(125		)
Loss on investment	(550		)
Fair value of investment as of December 31, 2018	$	14,525

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:



	December 31, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	96,500	$	96,500	$	411,000	$	411,000
5.375% Senior Notes due 2027⁽¹⁾	$	490,274	$	521,100	$	—	$	—

(1) The carrying value includes associated deferred loan costs and any discount.

The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the December 31, 2019 quoted market price, a Level 1 classification in the fair value hierarchy.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2019

Extractive Industries [Abstract]

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

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

Capitalized oil and natural gas costs

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



	December 31,
	2019			2018
	(In thousands)
Oil and natural gas interests:
Proved	$	1,316,692		$	845,228
Unproved	1,551,767			871,485
Total oil and natural gas interests	2,868,459			1,716,713
Accumulated depletion and impairment	(326,474		)	(248,296		)
Net oil and natural gas interests capitalized	$	2,541,985		$	1,468,417

Costs incurred in oil and natural gas activities

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



	December 31,
	2019		2018		2017
	(In thousands)
Acquisition costs:
Proved properties	$	471,464	$	256,055	$	55,948
Unproved properties	680,282		356,761		287,131
Total	$	1,151,746	$	612,816	$	343,079

Results of Operations from Oil and Natural Gas Producing Activities

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



	December 31,
	2019			2018			2017
	(In thousands)
Royalty income	$	293,811		$	282,661		$	160,163
Production and ad valorem taxes	(19,076		)	(19,048		)	(10,608		)
Gathering and transportation	—			—			(789		)
Depletion	(78,178		)	(58,830		)	(40,519		)
Income tax expense	(842		)	(422		)	—
Results of operations from oil, natural gas and natural gas liquids	$	195,715		$	204,361		$	108,247

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2019, 2018 and 2017 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

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

The changes in estimated proved reserves are as follows:



	Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)
	(In thousands)
Proved Developed and Undeveloped Reserves:
As of December 31, 2016	21,344		5,576		27,091
Purchase of reserves in place	2,106		252		5,245
Extensions and discoveries	7,859		1,813		11,106
Revisions of previous estimates	(2,525	)	(813	)	(3,498	)
Production	(2,899	)	(533	)	(3,549	)
As of December 31, 2017	25,885		6,295		36,395
Purchase of reserves in place	5,394		1,163		16,486
Extensions and discoveries	13,858		3,359		13,992
Revisions of previous estimates	1,140		1,108		564
Production	(4,399	)	(933	)	(5,840	)
As of December 31, 2018	41,878		10,992		61,597
Purchase of reserves in place	12,949		4,895		24,423
Extensions and discoveries	11,526		3,095		14,822
Revisions of previous estimates	(6,810	)	1,041		2,589
Production	(5,123	)	(1,459	)	(7,657	)
As of December 31, 2019	54,420		18,564		95,774

Proved Developed Reserves:
December 31, 2017	18,788		4,536		29,256
December 31, 2018	29,526		7,965		49,681
December 31, 2019	40,857		14,994		80,737

Proved Undeveloped Reserves:
December 31, 2017	7,097		1,759		7,139
December 31, 2018	12,352		3,027		11,916
December 31, 2019	13,563		3,570		15,037

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

During the year ended December 31, 2019, the Partnership’s extensions and discoveries of 17,091 MBOE resulted primarily from the drilling of 829 new wells and from 97 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 5,337 MBOE were due to proved undeveloped reserves downgrades and realized prices, which were partially offset by extensions and performance. The purchase of reserves in place of 21,914 MBOE were due to multiple acquisitions, primarily the Drop-Down transaction from Diamondback and the acquisition of certain mineral and royalty interests from Santa Elena Minerals, LP.

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

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

Standardized Measure of Discounted Future Net Cash Flows

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

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Partnership’s proved oil and natural gas reserves as of December 31, 2019, 2018 and 2017:



	December 31,
	2019			2018			2017
	(In thousands)
Future cash inflows	$	3,218,257		$	2,962,386		$	1,445,883
Future production taxes	(237,181		)	(200,079		)	(125,564		)
Future income tax expense	(150,373		)	(273,643		)	(6,932		)
Future net cash flows	2,830,703			2,488,664			1,313,387
10% discount to reflect timing of cash flows	(1,512,315		)	(1,349,282		)	(688,039		)
Standardized measure of discounted future net cash flows	$	1,318,388		$	1,139,382		$	625,348

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



	December 31,
	2019		2018		2017
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	52.86	$	61.46	$	48.21
Natural gas (per Mcf)	$	0.51	$	1.84	$	2.13
Natural gas liquids (per Bbl)	$	15.79	$	25.04	$	19.15

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



	December 31,
	2019			2018			2017
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	1,139,382		$	625,348		$	412,581
Purchase of minerals in place	339,814			180,990			54,662
Sales of oil and natural gas, net of production costs	(274,735		)	(266,055		)	(149,555		)
Extensions and discoveries	330,097			423,540			214,479
Net changes in prices and production costs	(301,182		)	187,592			99,382
Revisions of previous quantity estimates	(114,409		)	52,487			(50,773		)
Net changes in income taxes	56,502			(123,804		)	(1,129		)
Accretion of discount	126,650			62,867			41,477
Net changes in timing of production and other	16,269			(3,583		)	4,224
Standardized measure of discounted future net cash flows at the end of the period	$	1,318,388		$	1,139,382		$	625,348

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Use of Estimates

Cash and Cash Equivalents

Revenue from Contracts with Customers

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

to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

Transaction price allocated to remaining performance obligations

Contract balances

Prior-period performance obligations

Fair Value of Financial Instruments

Oil and Natural Gas Properties

The Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required.

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

Debt Issuance Costs

The costs are associated with the Partnership’s credit agreement and are being amortized over the term of the credit agreement.The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using the effective interest method.

Concentrations

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

Concentrations

Earnings Per Unit

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

Unit-based Compensation

Unit–Based Compensation

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

Income Taxes

Recent Accounting Pronouncements



Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”	This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.	Q1 2020	The Partnership adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”	This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consist of the following:



	December 31,
	2019		2018
	(In thousands)
Interest payable	$	6,718	$	728
Ad valorem taxes payable	5,632		5,039
Other	932		255
Total accrued liabilities	$	13,282	$	6,022

Schedule of Recent Aaccounting Pronouncements and the Partnership’s Analysis of the Effects on its Financial Statements

The following table provides a brief description of recent accounting pronouncements and the Partnership’s analysis of the effects on its financial statements:



Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”	This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.	Q1 2020	The Partnership adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”	This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.

Unitholders’ Equity and Partnership Distributions (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Schedule of Changes in Common Units

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



	Common Units
Balance at December 31, 2018	51,653,956
Common units issued in public offerings	10,925,000
Common units vested and issued under the LTIP	85,359
Units repurchased for tax withholding	(10,732	)
Common units issued for acquisition	5,152,124
Balance at December 31, 2019	67,805,707

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



	Class B Units
Balance at December 31, 2018	72,418,500
Units issued for the Drop-Down	18,291,446
Balance at December 31, 2019	90,709,946

Distributions Made to Limited Partner, by Distribution

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



Declaration Date	Quarter	Amount per Common Unit		Payment Date	Amount Distributed to Diamondback
					(in thousands)
April 28, 2017	Q1 2017	$	0.302	May 25, 2017	$	21,880
July 28, 2017	Q2 2017	$	0.332	August 24, 2017	$	24,286
October 16, 2017	Q3 2017	$	0.337	November 14, 2017	$	24,652
January 31, 2018	Q4 2017	$	0.460	February 26, 2018	$	33,649
April 5, 2018	Q1 2018	$	0.480	April 27, 2018	$	35,112
July 27, 2018	Q2 2018	$	0.600	August 20, 2018	$	43,901
October 23, 2018	Q3 2018	$	0.580	November 19, 2018	$	42,447
January 30, 2019	Q4 2018	$	0.510	February 25, 2019	$	37,326
April 25, 2019	Q1 2019	$	0.380	May 20, 2019	$	27,817
July 28, 2019	Q2 2019	$	0.470	August 21, 2019	$	34,400
October 25, 2019	Q3 2019	$	0.460	November 15, 2019	$	33,668

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Components of the Provision for Income Taxes

The components of the provision for income taxes for the years ended December 31, 2019 and 2018 are as follows:



	Year Ended December 31,
	2019			2018
	(In thousands)
Current income tax provision (benefit):
Federal	$	—		$	—
State	—			151
Total current income tax provision	—			151
Deferred income tax provision (benefit):
Federal	(41,582		)	(72,516		)
State	—			—
Total deferred income tax provision (benefit)	(41,582		)	(72,516		)
Total benefit from income taxes	$	(41,582	)	$	(72,365	)

Schedule of Reconciliation of the Statutory Federal Income Tax

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



	Year Ended December 31,
	2019			2018
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	37,722		$	40,008
Impact of net income attributable to the pre-incorporation period	—			(14,279		)
Impact of nontaxable noncontrolling interest	(36,735		)	(24,973		)
State income tax expense (benefit), net of federal tax effect	—			119
Deferred taxes related to change in tax status	(42,424		)	(72,787		)
Other, net	(145		)	(453		)
Provision for (benefit from) income taxes	$	(41,582	)	$	(72,365	)

Schedule of Deferred Tax Assets and Liabilities

The components of the Company’s deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows:



	Year Ended December 31,
	2019			2018
	(In thousands)
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$	7,958		$	2,131
Investment in the Operating Company	134,272			94,468
Other	237			284
Total deferred tax assets	142,467			96,883
Valuation allowance	(1		)	—
Net deferred tax assets	142,466			96,883
Deferred tax liabilities:
Oil and natural gas properties and equipment	—			—
Other	—			—
Total deferred tax liabilities	—			—
Net deferred tax assets (liabilities)	$	142,466		$	96,883

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

12 Months Ended

Dec. 31, 2019

Extractive Industries [Abstract]

Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities

Oil and natural gas interests include the following:



	December 31,
	2019			2018
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	1,316,692		$	845,228
Not subject to depletion	1,551,767			871,485
Gross oil and natural gas interests	2,868,459			1,716,713
Accumulated depletion and impairment	(326,474		)	(248,296		)
Oil and natural gas interests, net	2,541,985			1,468,417
Land	5,688			5,688
Property, net of accumulated depletion and impairment	$	2,547,673		$	1,474,105

Balance of costs not subject to depletion:
Incurred in 2019	$	827,680
Incurred in 2018	460,977
Incurred in 2017	263,110
Total not subject to depletion	$	1,551,767

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



	December 31,
	2019			2018
	(In thousands)
Oil and natural gas interests:
Proved	$	1,316,692		$	845,228
Unproved	1,551,767			871,485
Total oil and natural gas interests	2,868,459			1,716,713
Accumulated depletion and impairment	(326,474		)	(248,296		)
Net oil and natural gas interests capitalized	$	2,541,985		$	1,468,417

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

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



	December 31,
	2019		2018		2017
	(In thousands)
Acquisition costs:
Proved properties	$	471,464	$	256,055	$	55,948
Unproved properties	680,282		356,761		287,131
Total	$	1,151,746	$	612,816	$	343,079

Changes in Estimated Proved Reserves

The changes in estimated proved reserves are as follows:



	Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)
	(In thousands)
Proved Developed and Undeveloped Reserves:
As of December 31, 2016	21,344		5,576		27,091
Purchase of reserves in place	2,106		252		5,245
Extensions and discoveries	7,859		1,813		11,106
Revisions of previous estimates	(2,525	)	(813	)	(3,498	)
Production	(2,899	)	(533	)	(3,549	)
As of December 31, 2017	25,885		6,295		36,395
Purchase of reserves in place	5,394		1,163		16,486
Extensions and discoveries	13,858		3,359		13,992
Revisions of previous estimates	1,140		1,108		564
Production	(4,399	)	(933	)	(5,840	)
As of December 31, 2018	41,878		10,992		61,597
Purchase of reserves in place	12,949		4,895		24,423
Extensions and discoveries	11,526		3,095		14,822
Revisions of previous estimates	(6,810	)	1,041		2,589
Production	(5,123	)	(1,459	)	(7,657	)
As of December 31, 2019	54,420		18,564		95,774

Proved Developed Reserves:
December 31, 2017	18,788		4,536		29,256
December 31, 2018	29,526		7,965		49,681
December 31, 2019	40,857		14,994		80,737

Proved Undeveloped Reserves:
December 31, 2017	7,097		1,759		7,139
December 31, 2018	12,352		3,027		11,916
December 31, 2019	13,563		3,570		15,037

Standardized Measure of Discounted Future Net Cash Flows



	December 31,
	2019			2018			2017
	(In thousands)
Future cash inflows	$	3,218,257		$	2,962,386		$	1,445,883
Future production taxes	(237,181		)	(200,079		)	(125,564		)
Future income tax expense	(150,373		)	(273,643		)	(6,932		)
Future net cash flows	2,830,703			2,488,664			1,313,387
10% discount to reflect timing of cash flows	(1,512,315		)	(1,349,282		)	(688,039		)
Standardized measure of discounted future net cash flows	$	1,318,388		$	1,139,382		$	625,348

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

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



	December 31,
	2019		2018		2017
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	52.86	$	61.46	$	48.21
Natural gas (per Mcf)	$	0.51	$	1.84	$	2.13
Natural gas liquids (per Bbl)	$	15.79	$	25.04	$	19.15

Principal Changes in Standardized Measure of Discounted Future Net Cash Flows

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



	December 31,
	2019			2018			2017
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	1,139,382		$	625,348		$	412,581
Purchase of minerals in place	339,814			180,990			54,662
Sales of oil and natural gas, net of production costs	(274,735		)	(266,055		)	(149,555		)
Extensions and discoveries	330,097			423,540			214,479
Net changes in prices and production costs	(301,182		)	187,592			99,382
Revisions of previous quantity estimates	(114,409		)	52,487			(50,773		)
Net changes in income taxes	56,502			(123,804		)	(1,129		)
Accretion of discount	126,650			62,867			41,477
Net changes in timing of production and other	16,269			(3,583		)	4,224
Standardized measure of discounted future net cash flows at the end of the period	$	1,318,388		$	1,139,382		$	625,348

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

- Definition

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References + Details

Organization and Basis of Presentation (Details) - USD ($) $ in Thousands			1 Months Ended		2 Months Ended	12 Months Ended
	May 10, 2018	May 09, 2018	Mar. 31, 2019	Jul. 31, 2018	Jun. 30, 2018	Dec. 31, 2019
Limited Partners' Capital Account [Line Items]
Percent of general partner interest	36.00%					100.00%
General partners' cash capital contribution	$ 1,000
Limited partners' cash capital contribution	$ 1,000
Limited partners capital account, percentage of distribution	8.00%
Number of class B units converted (in shares)	731,500
Partners' capital account, units, converted (in shares)	731,500
Limited partners' cash account					$ 10
Diamondback Energy, Inc.
Limited Partners' Capital Account [Line Items]
Number of common stock exchanged (in shares)		73,150,000
Number of shares issues (in shares)		73,150,000
Diamondback Energy, Inc. \| Viper Energy Partners LP
Limited Partners' Capital Account [Line Items]
Percent of limited partnership interest	64.00%		54.00%	59.00%		58.00%
Viper Energy Partners LP \| Viper LLC
Limited Partners' Capital Account [Line Items]
Percent of general partner interest				41.00%
Class B Units
Limited Partners' Capital Account [Line Items]
Units of partnership interest, amount (in shares)		73,150,000

Summary of Significant Accounting Policies - Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Interest payable	$ 6,718	$ 728
Ad valorem taxes payable	5,632	5,039
Other	932	255
Total accrued liabilities	$ 13,282	$ 6,022

Summary of Significant Accounting Policies - Oil and Natural Gas Properties, and Debt Issuance Costs (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) $ / Boe	Dec. 31, 2018 USD ($) $ / Boe	Dec. 31, 2017 USD ($) $ / Boe
Accounting Policies [Abstract]
Average depletion rate per barrel equivalent unit of production \| $ / Boe	9.95	9.33	10.07
Depletion for oil and natural gas properties	$ 78,178,000	$ 58,830,000	$ 40,519,000
Impairment of oil and gas properties	0	0	0
Debt issuance costs, net of accumulated amortizations	6,600,000	5,500,000	4,400,000
Debit issuance costs, accumulated amortization	3,100,000	2,200,000	1,400,000
Debt capitalized costs	2,500,000	0	0
Debt accumulated amortization	$ 50,000.00	$ 0	$ 0

Acquisitions (Details)						1 Months Ended		12 Months Ended
Acquisitions (Details)	Oct. 31, 2019 a	Oct. 01, 2019 USD ($) a shares	Sep. 05, 2019	Jul. 26, 2019	Aug. 15, 2018 USD ($) a	Oct. 31, 2019 USD ($) shares	May 31, 2017 shares	Dec. 31, 2019 USD ($) a	Dec. 31, 2018 USD ($) a	Dec. 31, 2017 USD ($) a	Sep. 30, 2019 USD ($)
Business Acquisition [Line Items]
Payments to acquire mineral rights								$ 530,572,000	$ 610,131,000	$ 344,079,000
Mineral properties, gross (in acres) \| a								814,224
Mineral properties, net royalty (acres) \| a								24,304	14,841	9,570
Revolving Credit Facility
Business Acquisition [Line Items]
Current borrowing capacity								$ 775,000,000.0
Diamondback Energy, Inc.
Business Acquisition [Line Items]
Percentage of mineral acres operated by affiliate								50.00%
Drop-Down Acquisition
Business Acquisition [Line Items]
Business acquisition, equity interests issued, number of trading days period to decide weighted average sale price				10 days
Drop-Down Acquisition \| Revolving Credit Facility
Business Acquisition [Line Items]
Credit facility, increase of borrowing base		$ 125,000,000.0
Current borrowing capacity		$ 725,000,000.0									$ 600,000,000.0
Drop-Down Acquisition \| Diamondback Energy, Inc.
Business Acquisition [Line Items]
Percentage of mineral acres operated by affiliate		95.00%
Drop-Down Acquisition \| Diamondback Energy, Inc.
Business Acquisition [Line Items]
Number of units issued in acquisition (in shares) \| shares		18,300,000
Fair value consideration of units issued in acquisition		$ 497,200,000
Payments to acquire mineral rights		190,200,000
Aggregate purchase price		$ 687,400,000
Mineral properties acquired, net royalty (acres) \| a		5,490
Percentage of average net royalty interest in acquired mineral and royalty interests		3.20%
Santa Elena Acquisition
Business Acquisition [Line Items]
Number of units issued in acquisition (in shares) \| shares						5,200,000
Fair value consideration of units issued in acquisition						$ 124,000,000.0
Business acquisition, equity interests issued, number of trading days period to decide weighted average sale price			5 days
Mineral properties acquired, net royalty (acres) \| a	1,366
Percentage of average net royalty interest in acquired mineral and royalty interests	5.60%
Other mineral interests acquired in 2019
Business Acquisition [Line Items]
Aggregate purchase price								$ 343,700,000
Mineral properties acquired, net royalty (acres) \| a								2,607
Mineral properties acquired, gross acres (acres) \| a								136,012
Mineral interests acquired in 2018
Business Acquisition [Line Items]
Payments to acquire mineral rights									$ 440,400,000
Mineral properties acquired, net royalty (acres) \| a									3,585
Mineral interests acquired in Permian Basin \| Diamondback Energy, Inc.
Business Acquisition [Line Items]
Percentage of mineral acres operated by affiliate					80.00%
Mineral interests acquired in Permian Basin \| Diamondback Energy, Inc.
Business Acquisition [Line Items]
Aggregate purchase price					$ 175,000,000.0
Mineral properties acquired, net royalty (acres) \| a					1,696
Mineral properties acquired, gross acres (acres) \| a					32,424
Mineral interests acquired in 2017
Business Acquisition [Line Items]
Payments to acquire mineral rights										$ 343,100,000
Mineral properties acquired, net royalty (acres) \| a										3,157
Mineral interests acquired in 2017 \| Private Placement \| Revolving Credit Facility
Business Acquisition [Line Items]
Stock issued during period for acquisition (in shares) \| shares							174,513

Oil and Natural Gas Interests (Details) - USD ($)	12 Months Ended
Oil and Natural Gas Interests (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Subject to depletion	$ 1,316,692,000	$ 845,228,000
Not subject to depletion	1,551,767,000	871,485,000
Gross oil and natural gas interests	2,868,459,000	1,716,713,000
Accumulated depletion and impairment	(326,474,000)	(248,296,000)
Oil and natural gas interests, net	2,541,985,000	1,468,417,000
Land	5,688,000	5,688,000
Property, net	2,547,673,000	1,474,105,000
Balance of costs not subject to depletion:	827,680,000	460,977,000	$ 263,110,000
Impairment	$ 0	$ 0	$ 0
Minimum
Property, Plant and Equipment [Line Items]
Anticipated timing of cost inclusion in amortization calculation	3 years
Maximum
Property, Plant and Equipment [Line Items]
Anticipated timing of cost inclusion in amortization calculation	5 years

Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Unamortized debt issuance costs	$ (2,458)	$ 0
Unamortized discount costs	(7,268)	0
Total long-term debt	586,774	411,000
5.375 % Senior Notes due 2027
Line of Credit Facility [Line Items]
Long term debt gross	500,000	0
Revolving credit facility
Line of Credit Facility [Line Items]
Long term debt gross	$ 96,500	$ 411,000

Debt - Additional Information (Details)		12 Months Ended
Debt - Additional Information (Details)	Oct. 16, 2019 USD ($)	Dec. 31, 2019 USD ($) redetermindation	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Oct. 01, 2019 USD ($)	Sep. 30, 2019 USD ($)	Jul. 31, 2018 USD ($)	Jul. 20, 2018 USD ($)
Line of Credit Facility [Line Items]
Proceeds from issuance of senior long-term debt		$ 500,000,000	$ 0	$ 0
Senior Notes
Line of Credit Facility [Line Items]
Maximum issuance of unsecured debt		1,000,000,000.0				$ 400,000,000.0
Revolving Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity								$ 2,000,000,000.0
Current borrowing capacity		$ 775,000,000.0
Number of additional redeterminations that may be requested \| redetermindation		3
Period of redeterminations		12 months
Amount outstanding under credit facility		$ 96,500,000					$ 361,500,000
Remaining borrowing capacity		$ 678,500,000
Revolving Credit Facility \| Fed Funds Effective Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.50%
Revolving Credit Facility \| LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.00%
Revolving Credit Facility \| Minimum
Line of Credit Facility [Line Items]
Commitment fee on the unused portion of the borrowing base		0.375%
Revolving Credit Facility \| Minimum \| LIBOR
Line of Credit Facility [Line Items]
Debt instrument applicable margin		1.75%
Revolving Credit Facility \| Minimum \| Base Rate
Line of Credit Facility [Line Items]
Debt instrument applicable margin		0.75%
Revolving Credit Facility \| Maximum
Line of Credit Facility [Line Items]
Commitment fee on the unused portion of the borrowing base		0.50%
Revolving Credit Facility \| Maximum \| LIBOR
Line of Credit Facility [Line Items]
Debt instrument applicable margin		2.75%
Revolving Credit Facility \| Maximum \| Base Rate
Line of Credit Facility [Line Items]
Debt instrument applicable margin		1.75%
5.375 % Senior Notes due 2027 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, face amount	$ 500,000,000.0
Debt instrument, interest rate, stated percentage	5.375%
Proceeds from issuance of senior long-term debt	$ 490,000,000.0
Drop-Down Acquisition \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Current borrowing capacity					$ 725,000,000.0	$ 600,000,000.0
Credit facility, increase of borrowing base					$ 125,000,000.0

Related Party Transactions (Details)				12 Months Ended
Related Party Transactions (Details)	Oct. 01, 2019 USD ($) a	Aug. 15, 2018 USD ($) a	Jun. 23, 2014 USD ($)	Dec. 31, 2019 USD ($) lease	Dec. 31, 2018 USD ($) lease	Dec. 31, 2017 USD ($)
Related Party Transaction [Line Items]
State income tax expense				$ 0	$ 151,000	$ 0
General Partner \| Partnership Agreement
Related Party Transaction [Line Items]
Incurred costs for transactions with related party				3,100,000	2,500,000	2,500,000
Affiliated Entity \| Advisory Services Agreement
Related Party Transaction [Line Items]
Incurred costs for transactions with related party				$ 0	0	0
Advisory services agreement, annual fee			$ 500,000
Diamondback Energy, Inc.
Related Party Transaction [Line Items]
Percentage of mineral acres operated by affiliate				50.00%
Diamondback Energy, Inc. \| Drop-Down Acquisition
Related Party Transaction [Line Items]
Percentage of mineral acres operated by affiliate	95.00%
Diamondback Energy, Inc. \| Mineral interests acquired in Permian Basin
Related Party Transaction [Line Items]
Percentage of mineral acres operated by affiliate		80.00%
Diamondback Energy, Inc. \| Affiliated Entity
Related Party Transaction [Line Items]
Revenue from related parties				$ 300,000	2,500,000	$ 100,000
Revenue from related parties on new leases				$ 200,000	$ 600,000
Number of leases extended				6	13	2
Number of new leases \| lease				4	1
Diamondback Energy, Inc. \| Drop-Down Acquisition
Related Party Transaction [Line Items]
Aggregate purchase price	$ 687,400,000
Mineral properties acquired, net royalty (acres) \| a	5,490
Diamondback Energy, Inc. \| Mineral interests acquired in Permian Basin
Related Party Transaction [Line Items]
Aggregate purchase price		$ 175,000,000.0
Mineral properties acquired, gross acres (acres) \| a		32,424
Mineral properties acquired, net royalty (acres) \| a		1,696

Unit-Based Compensation - Phantom Units (Details) - Phantom Share Units (PSUs) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Unvested at December 31, 2018 \| shares	125,053
Granted \| shares	56,582
Vested \| shares	(85,359)
Forfeited \| shares	(1,028)
Unvested at December 31, 2019 \| shares	95,248
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested at December 31, 2018 \| $ / shares	$ 23.44
Granted \| $ / shares	30.33
Vested \| $ / shares	23.96
Forfeited \| $ / shares	42.50
Unvested at December 31, 2019 \| $ / shares	$ 26.87
Aggregate fair value of phantom units that vested during period \| $	$ 2.0
Unrecognized compensation cost related to unvested phantom units \| $	$ 1.5
Unrecognized compensation cost related to unvested phantom units, period of recognition	1 year 3 days

Unitholders’ Equity and Partnership Distributions - Additional Information (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
	May 10, 2018	Mar. 31, 2019	Jul. 31, 2018	Dec. 31, 2019	Feb. 07, 2020	Dec. 31, 2018
Cash Distribution
Limited Partners' Capital Account [Line Items]
Cash distributions, distribution period after quarter end				60 days
Common Units
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units issued (in shares)				67,805,707		51,653,956
Limited partners' capital account, units outstanding				67,805,707		51,653,956
Units issued in public offering (in shares)				10,925,000
Common Units \| Follow-on Public Offering
Limited Partners' Capital Account [Line Items]
Units issued in public offering (in shares)		10,925,000	10,080,000
Sale of stock, consideration received on transaction		$ 340.6	$ 303.1
Common Units \| Over-Allotment Option
Limited Partners' Capital Account [Line Items]
Units issued in public offering (in shares)		1,425,000	1,080,000
Class B Units
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units issued (in shares)				90,709,946		72,418,500
Limited partners' capital account, units outstanding				90,709,946	90,709,946	72,418,500
Diamondback Energy, Inc. \| Common Units
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units outstanding				731,500
Diamondback Energy, Inc. \| Class B Units
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units outstanding				90,709,946
Viper Energy Partners LP \| Diamondback Energy, Inc.
Limited Partners' Capital Account [Line Items]
Percent of limited partnership interest	64.00%	54.00%	59.00%	58.00%
Revolving Credit Facility
Limited Partners' Capital Account [Line Items]
Amount outstanding under credit facility			$ 361.5	$ 96.5

Unitholders’ Equity and Partnership Distributions - Changes in Number of Partnership's units (Details)	12 Months Ended
	Dec. 31, 2019 shares
Common Units
Class of Stock [Line Items]
Beginning balance (in shares)	51,653,956
Common units issued in public offerings (in shares)	10,925,000
Common units vested and issued under the LTIP (in shares)	85,359
Units repurchased for tax withholding (in shares)	(10,732)
Common units issued for acquisition (in shares)	5,152,124
Ending balance (in shares)	67,805,707
Class B Units
Class of Stock [Line Items]
Beginning balance (in shares)	72,418,500
Units issued for the drop-down (in shares)	18,291,446
Ending balance (in shares)	90,709,946

Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Net income attributable to the period	$ 2,291	$ 7,946	$ 2,265	$ 33,779	$ (688)	$ 2,346	$ 99,404	$ 42,896	$ 46,281	$ 143,958	$ 111,478
Basic weighted average common units outstanding (in shares)									61,744	71,546	104,318
Dilutive Securities, Effect on Basic Earnings Per Share [Abstract]
Potential common units issuable (in shares)									43	80	65
Diluted weighted average common units outstanding (in shares)									61,787	71,626	104,383
Net income per common unit, basic (dollars per shares)	$ 0.03	$ 0.13	$ 0.04	$ 0.61	$ (0.01)	$ 0.05	$ 1.36	$ 0.38	$ 0.75	$ 2.01	$ 1.07
Net income per common unit, diluted (dollars per shares)	$ 0.03	$ 0.13	$ 0.04	$ 0.61	$ (0.01)	$ 0.05	$ 1.35	$ 0.38	$ 0.75	$ 2.01	$ 1.07
Antidilutive securities, restricted stock units (in shares)									0	1	40

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Effective income tax rates	(23.10%)	(38.00%)
Net deferred tax assets	$ 142,466,000	$ 96,883,000
Income tax benefit	42,424,000	72,787,000
Federal net operating loss carryforwards may be carried forward indefinitely	37,900,000
Income tax expense	$ 0	$ 151,000	$ 0

Income Taxes - Components of Provision for Income Taxes (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current income tax provision (benefit):
Federal									$ 0	$ 0
State									0	151,000	$ 0
Total current income tax provision									0	151,000
Deferred income tax provision (benefit):
Federal									(41,582,000)	(72,516,000)
State									0	0
Total deferred income tax provision (benefit)									(41,582,000)	(72,516,000)	0
Total benefit from income taxes	$ 326,000	$ (7,480,000)	$ 180,000	$ (34,608,000)	$ (1,251,000)	$ 764,000	$ (71,878,000)	$ 0	$ (41,582,000)	$ (72,365,000)	$ 0

Income Taxes - Reconciliation of Statutory Federal Income tax (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the federal statutory rate (21%)									$ 37,722	$ 40,008
Impact of net income attributable to the pre-incorporation period									0	(14,279)
Impact of nontaxable noncontrolling interest									(36,735)	(24,973)
State income tax expense (benefit), net of federal tax effect									0	119
Deferred taxes related to change in tax status									(42,424)	(72,787)
Other, net									(145)	(453)
Total benefit from income taxes	$ 326	$ (7,480)	$ 180	$ (34,608)	$ (1,251)	$ 764	$ (71,878)	$ 0	$ (41,582)	$ (72,365)	$ 0

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$ 7,958	$ 2,131
Investment in the Operating Company	134,272	94,468
Other	237	284
Total deferred tax assets	142,467	96,883
Valuation allowance	(1)	0
Net deferred tax assets	142,466	96,883
Deferred tax liabilities:
Oil and natural gas properties and equipment	0	0
Other	0	0
Total deferred tax liabilities	0	0
Net deferred tax assets (liabilities)	$ 142,466	$ 96,883

Fair Value Measurements - Changes in Fair Value of the Partnership's Investment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impact of adoption of Accounting Standards Update 2016-01				$ (18,651)
Gain (loss) on investment	$ 4,832	$ (550)	$ 0
Fair Value, Recurring \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Beginning Balance	14,525	33,851
Impact of adoption of Accounting Standards Update 2016-01				$ (18,651)
Disposal of shares		(125)
Gain (loss) on investment	4,832	(550)
Ending Balance	$ 19,357	$ 14,525	$ 33,851

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas interests:
Proved	$ 1,316,692	$ 845,228
Unproved	1,551,767	871,485
Total oil and natural gas interests	2,868,459	1,716,713
Accumulated depletion and impairment	(326,474)	(248,296)
Net oil and natural gas interests capitalized	$ 2,541,985	$ 1,468,417

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Results of Operation from Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Royalty income	$ 293,811	$ 282,661	$ 160,163
Production and ad valorem taxes	(19,076)	(19,048)	(10,608)
Gathering and transportation	0	0	(789)
Depletion	(78,178)	(58,830)	(40,519)
Income tax expense	(842)	(422)	0
Results of operations from oil, natural gas and natural gas liquids	$ 195,715	$ 204,361	$ 108,247

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Changes in Estimated Proved Reserves (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2019 Boe Mcf bbl	Dec. 31, 2018 Boe Mcf bbl	Dec. 31, 2017 Boe Mcf bbl
Proved Developed and Undeveloped Reserves [Roll Forward]
Partnership’s extensions and discoveries (Energy) \| Boe	17,091	19,549	11,524
Oil and gas, development well drilled, net productive, number	829	133	96
New proved undeveloped location	97	138	40
Revision of previous estimate (Energy) \| Boe	(5,337)	2,342	(3,921)
Purchase of reserves (Energy) \| Boe	21,914	9,305	3,232
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	41,878	25,885	21,344
Purchase of reserves in place	12,949	5,394	2,106
Extensions and discoveries	11,526	13,858	7,859
Revisions of previous estimates	(6,810)	1,140	(2,525)
Production	(5,123)	(4,399)	(2,899)
End of period	54,420	41,878	25,885
Proved developed reserves (Volume)	40,857	29,526	18,788
Proved undeveloped reserve (Volume)	13,563	12,352	7,097
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	10,992	6,295	5,576
Purchase of reserves in place	4,895	1,163	252
Extensions and discoveries	3,095	3,359	1,813
Revisions of previous estimates	1,041	1,108	(813)
Production	(1,459)	(933)	(533)
End of period	18,564	10,992	6,295
Proved developed reserves (Volume)	14,994	7,965	4,536
Proved undeveloped reserve (Volume)	3,570	3,027	1,759
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period \| Mcf	61,597	36,395	27,091
Purchase of reserves in place \| Mcf	24,423	16,486	5,245
Extensions and discoveries \| Mcf	14,822	13,992	11,106
Revisions of previous estimates \| Mcf	2,589	564	(3,498)
Production \| Mcf	(7,657)	(5,840)	(3,549)
End of period \| Mcf	95,774	61,597	36,395
Proved developed reserves (Volume) \| Mcf	80,737	49,681	29,256
Proved undeveloped reserve (Volume) \| Mcf	15,037	11,916	7,139

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Future cash inflows	$ 3,218,257	$ 2,962,386	$ 1,445,883
Future production taxes	(237,181)	(200,079)	(125,564)
Future income tax expense	(150,373)	(273,643)	(6,932)
Future net cash flows	2,830,703	2,488,664	1,313,387
10% discount to reflect timing of cash flows	(1,512,315)	(1,349,282)	(688,039)
Standardized measure of discounted future net cash flows	$ 1,318,388	$ 1,139,382	$ 625,348	$ 412,581

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at the beginning of the period	$ 1,139,382	$ 625,348	$ 412,581
Purchase of minerals in place	339,814	180,990	54,662
Sales of oil and natural gas, net of production costs	(274,735)	(266,055)	(149,555)
Extensions and discoveries	330,097	423,540	214,479
Net changes in prices and production costs	(301,182)	187,592	99,382
Revisions of previous quantity estimates	(114,409)	52,487	(50,773)
Net changes in income taxes	56,502	(123,804)	(1,129)
Accretion of discount	126,650	62,867	41,477
Net changes in timing of production and other	16,269	(3,583)	4,224
Standardized measure of discounted future net cash flows at the end of the period	$ 1,318,388	$ 1,139,382	$ 625,348

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Operating income	$ 92,711	$ 71,788	$ 72,194	$ 61,590	$ 73,665	$ 77,714	$ 75,263	$ 62,178	$ 298,283	$ 288,820	$ 172,033
Income from operations	57,411	46,555	49,570	40,004	49,512	54,846	54,926	43,703	193,540	202,987	113,821
Income tax expense (benefit)	326	(7,480)	180	(34,608)	(1,251)	764	(71,878)	0	(41,582)	(72,365)	0
Net income	48,528	51,097	47,274	74,311	40,705	50,812	128,464	42,896
Net income attributable to non-controlling interest	46,237	43,151	45,009	40,532	41,393	48,466	29,060	0	174,929	118,919	0
Net income attributable to the period	$ 2,291	$ 7,946	$ 2,265	$ 33,779	$ (688)	$ 2,346	$ 99,404	$ 42,896	$ 46,281	$ 143,958	$ 111,478
Net income per common unit, basic (dollars per shares)	$ 0.03	$ 0.13	$ 0.04	$ 0.61	$ (0.01)	$ 0.05	$ 1.36	$ 0.38	$ 0.75	$ 2.01	$ 1.07
Net income per common unit, diluted (dollars per shares)	$ 0.03	$ 0.13	$ 0.04	$ 0.61	$ (0.01)	$ 0.05	$ 1.35	$ 0.38	$ 0.75	$ 2.01	$ 1.07

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES The Partnership is a party to various legal proceedings, disputes and claims from time to time arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry. These proceedings, disputes and claims may include differing interpretations as to the prices at which crude oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, title claims, environmental issues and other matters. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Partnership, cannot be predicted with certainty, the Partnership believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, cash flows or results of operations. The Partnership’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Partnership’s assessment. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Cash Distribution On February 7, 2020, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2019 of $0.45 per common unit, payable on February 28, 2020, to unitholders of record at the close of business on February 21, 2020.

Summary of Significant Accounting Policies - Concentrations (Details) - Customer Concentration Risk - Royalty Interest Revenue	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Trafigura Trading LLC
Concentration Risk [Line Items]
Percent of total royalty interest revenue	27.00%	11.00%
Concho Resources, Inc
Concentration Risk [Line Items]
Percent of total royalty interest revenue	16.00%	16.00%
Shell Trading
Concentration Risk [Line Items]
Percent of total royalty interest revenue	12.00%	31.00%	47.00%
RSP Permian LLC
Concentration Risk [Line Items]
Percent of total royalty interest revenue			23.00%

Unit-Based Compensation - Additional Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Payment Arrangement [Abstract]
Common units reserved for issuance	8,892,918
Unit-based compensation expenses incurred	$ 1.8	$ 2.8	$ 2.4

Fair Value Measurements - Fair Value of Financial Instruments Not Recorded at Fair Value (Details) - Fair Value, Nonrecurring - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Carrying Value \| Revolving credit facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value	$ 96,500	$ 411,000
Carrying Value \| 5.375 % Senior Notes due 2027
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value	490,274	0
Fair Value \| Revolving credit facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value	96,500	411,000
Fair Value \| 5.375 % Senior Notes due 2027
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value	$ 521,100	$ 0

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Feb. 07, 2020	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas interests, based on the full cost method of accounting, amount excluded from depletion		$ 1,551,767	$ 871,485
Common Units
Limited partners' capital account, units issued (in shares)		67,805,707	51,653,956
Limited partners' capital account, units outstanding (in shares)		67,805,707	51,653,956
Class B Units
Limited partners' capital account, units issued (in shares)		90,709,946	72,418,500
Limited partners' capital account, units outstanding (in shares)	90,709,946	90,709,946	72,418,500

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids (Details)	12 Months Ended
	Dec. 31, 2019 $ / Mcf $ / bbl	Dec. 31, 2018 $ / Mcf $ / bbl	Dec. 31, 2017 $ / Mcf $ / bbl
Oil
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Unweighted arithmetic average first-day-of-the-month prices	52.86	61.46	48.21
Natural Gas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Unweighted arithmetic average first-day-of-the-month prices \| $ / Mcf	0.51	1.84	2.13
Natural Gas Liquids
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Unweighted arithmetic average first-day-of-the-month prices	15.79	25.04	19.15

Label	Element	Value
Common Stock [Member] \| Limited Partner [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (18,651,000)