0001602065-21-000006 | 10-K | XBRL Viewer

Cover - USD ($) $ in Millions	12 Months Ended
Cover - USD ($) $ in Millions	Dec. 31, 2020	Feb. 19, 2021	Jun. 30, 2020	Dec. 31, 2019
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 691.5
Entity Common Units, Units Outstanding		65,293,828
Documents Incorporated by Reference	Documents Incorporated By Reference: None
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0001602065
Class B Units
Entity Information [Line Items]
Limited partners' capital account, units outstanding	90,709,946	90,709,946		90,709,946

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 19,121	$ 3,602
Royalty income receivable (net of allowance for credit losses)	32,210	58,089
Royalty income receivable—related party	1,998	10,576
Other current assets	665	397
Total current assets	53,994	72,664
Property:
Oil and natural gas interests, full cost method of accounting ($1,364,906 and $1,551,767 excluded from depletion at December 31, 2020 and December 31, 2019, respectively)	2,895,542	2,868,459
Land	5,688	5,688
Accumulated depletion and impairment	(496,176)	(326,474)
Property, net	2,405,054	2,547,673
Deferred tax asset (net of allowance)	0	142,466
Other assets	2,327	22,823
Total assets	2,461,375	2,785,626
Current liabilities:
Accounts payable	43	0
Accounts payable—related party	0	150
Accrued liabilities	18,262	13,282
Derivative instruments	26,593	0
Total current liabilities	44,898	13,432
Long-term debt, net	555,644	586,774
Total liabilities	600,542	600,206
Commitments and contingencies (Note 12)
Unitholders’ equity:
General partner	809	889
Common units (65,817,281 units issued and outstanding as of December 31, 2020 and 67,805,707 units issued and outstanding as of December 31, 2019)	633,415	929,116
Class B units (90,709,946 units issued and outstanding December 31, 2020 and December 31, 2019)	1,031	1,130
Total Viper Energy Partners LP unitholders’ equity	635,255	931,135
Non-controlling interest	1,225,578	1,254,285
Total equity	1,860,833	2,185,420
Total liabilities and unitholders’ equity	$ 2,461,375	$ 2,785,626

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Feb. 19, 2021	Dec. 31, 2020	Dec. 31, 2019
Oil and natural gas interests, based on the full cost method of accounting, amount excluded from depletion		$ 1,364,906	$ 1,551,767
Common Units
Limited partners' capital account, units issued (in shares)		65,817,281	67,805,707
Limited partners' capital account, units outstanding (in shares)		65,817,281	67,805,707
Class B Units
Limited partners' capital account, units issued (in shares)		90,709,946	90,709,946
Limited partners' capital account, units outstanding (in shares)	90,709,946	90,709,946	90,709,946

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating income:
Royalty income	$ 246,981	$ 293,811	$ 282,661
Lease bonus income	2,585	4,117	6,029
Other operating income	1,060	355	130
Total operating income	250,626	298,283	288,820
Costs and expenses:
Production and ad valorem taxes	19,844	19,076	19,048
Depletion	100,501	78,178	58,830
Impairment	69,202	0	0
General and administrative expenses	8,165	7,489	7,955
Total costs and expenses	197,712	104,743	85,833
Income (loss) from operations	52,914	193,540	202,987
Other income (expense):
Interest expense, net	(33,000)	(21,076)	(13,849)
Gain (loss) on derivative instruments, net	(63,591)	0	0
Gain (loss) on revaluation of investment	(8,556)	4,832	(550)
Other income, net	1,286	2,332	1,924
Total other expense, net	(103,861)	(13,912)	(12,475)
Income (loss) before income taxes	(50,947)	179,628	190,512
Provision for (benefit from) income taxes	142,466	(41,582)	(72,365)
Net income (loss)	(193,413)	221,210	262,877
Net income (loss) attributable to non-controlling interest	(1,109)	174,929	118,919
Net income (loss) attributable to Viper Energy Partners LP	$ (192,304)	$ 46,281	$ 143,958
Net income (loss) attributable to common limited partner units:
Basic (dollars per shares)	$ (2.84)	$ 0.75	$ 2.01
Diluted (dollars per shares)	$ (2.84)	$ 0.75	$ 2.01
Weighted average number of common limited partner units outstanding:
Basic (in shares)	67,686	61,744	71,546
Diluted (in shares)	67,686	61,787	71,626
Revenue extensible list	us-gaap:RoyaltyMember

Statement of Consolidated Unitholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Drop-Down Acquisition	Impact of adoption of ASU 2016-01	General Partner	Non-Controlling Interest	Non-Controlling Interest Drop-Down Acquisition	Common Units	Common Units Limited Partners	Common Units Limited Partners Impact of adoption of ASU 2016-01	Class B Units Limited Partners	Class B Units Limited Partners Drop-Down Acquisition
Beginning balance (in shares) at Dec. 31, 2017								113,882		0
Beginning balance at Dec. 31, 2017	$ 913,908		$ (18,651)	$ 0	$ 0			$ 913,908	$ (18,651)	$ 0
Increase (Decrease) in Partners' Capital
Unit exchange related to tax conversion (in shares)								(73,150)		73,150
Unit exchange related to tax conversion	2,000			1,000	545,441			$ (545,441)		$ 1,000
Recapitalization related to tax conversion (in shares)								732		(732)
Recapitalization related to tax conversion	(10)									$ (10)
Net proceeds from the issuance of common units - public (in shares)								10,080
Net proceeds from the issuance of common units - public	303,121							$ 303,121
Unit-based compensation (in shares)								103
Unit-based compensation	2,763							$ 2,763
Unit options exercised (in shares)								8
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 (loss)	262,877				118,919			$ 143,958
Ending balance (in shares) at Dec. 31, 2018								51,654		72,419
Ending balance at Dec. 31, 2018	$ 1,237,042			1,000	694,940			$ 540,112		$ 990
Increase (Decrease) in Partners' Capital
Accounting standards update extensible list	us-gaap:AccountingStandardsUpdate201601Member
Net proceeds from the issuance of common units - public (in shares)								10,925
Net proceeds from the issuance of common units - public	$ 340,860							$ 340,860
Units issued for acquisition (in shares)								5,152			18,291
Units issued for acquisition	124,012	$ 497,412				$ 497,162		$ 124,012			$ 250
Unit-based compensation (in shares)								85
Unit-based compensation	1,822							$ 1,822
Offering costs	(221)							(221)
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)								(11)
Units repurchased for tax withholding	(353)							$ (353)
Net income (loss)	221,210				174,929			$ 46,281
Ending balance (in shares) at Dec. 31, 2019								67,806		90,710
Ending balance at Dec. 31, 2019	2,185,420			889	1,254,285			$ 929,116		$ 1,130
Increase (Decrease) in Partners' Capital
Unit-based compensation (in shares)								73
Unit-based compensation	1,272							$ 1,272
Distribution equivalent rights payments	(44)							(44)
Distributions to public	(45,630)							(45,630)
Distributions to Diamondback	(62,282)				(61,685)			(498)		$ (99)
Distributions to General Partner	(80)			(80)				0
Change in ownership of consolidated subsidiaries, net	0				34,087			$ (34,087)
Units repurchased for tax withholding (in shares)								(17)
Units repurchased for tax withholding	(384)							$ (384)
Repurchased units as part of unit buyback (in shares)							(2,045)
Repurchased units as part of unit buyback	(24,026)						$ (24,026)
Net income (loss)	(193,413)				(1,109)			$ (192,304)
Ending balance (in shares) at Dec. 31, 2020								65,817		90,710
Ending balance at Dec. 31, 2020	$ 1,860,833			$ 809	$ 1,225,578			$ 633,415		$ 1,031

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (193,413)	$ 221,210	$ 262,877
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) income taxes	142,466	(41,582)	(72,516)
Depletion	100,501	78,178	58,830
Impairment	69,202	0	0
(Gain) loss on derivative instruments, net	63,591	0	0
Net cash payments on derivatives	(36,998)	0	0
(Gain) loss on revaluation of investment	8,556	(4,832)	550
Other	3,589	2,800	3,500
Changes in operating assets and liabilities:
Royalty income receivable	25,879	(19,266)	(13,069)
Royalty income receivable—related party	8,578	(7,087)	1,653
Accounts payable and accrued liabilities	5,023	7,091	2,545
Other	(418)	179	123
Net cash provided by (used in) operating activities	196,556	236,691	244,493
Cash flows from investing activities:
Acquisitions of oil and natural gas interests	(65,678)	(530,572)	(610,131)
Acquisition of land	0	0	(4,687)
Proceeds from sale of assets	38,594	0	441
Proceeds from the sale of investments	10,801	0	124
Net cash provided by (used in) investing activities	(16,283)	(530,572)	(614,253)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	104,000	590,500	691,500
Repayment on credit facility	(116,500)	(905,000)	(374,000)
Proceeds from senior notes	0	500,000	0
Repayment of senior notes	(19,697)	0	0
Debt issuance costs	(111)	(10,863)	(1,039)
Proceeds from public offerings	0	340,860	305,773
Repurchased units as part of unit buyback	(24,026)	0	0
Distributions to public	(45,674)	(107,074)	(98,333)
Distributions to General Partner	(62,282)	(133,211)	(155,109)
Other	(464)	(405)	(553)
Net cash provided by (used in) financing activities	(164,754)	274,807	368,239
Net increase (decrease) in cash	15,519	(19,074)	(1,521)
Cash and cash equivalents at beginning of period	3,602	22,676	24,197
Cash and cash equivalents at end of period	19,121	3,602	22,676
Supplemental disclosure of cash flow information:
Interest paid	33,121	13,803	12,438
Supplemental disclosure of non—cash transactions:
OpCo units issued for the Drop-Down transaction (Note 4)	0	497,162	0
Common units issued for acquisition	$ 0	$ 124,012	$ 0

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2020
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 focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin. Since May 10, 2018, the Partnership has been treated as a corporation for U.S. federal income tax purposes. As of December 31, 2020, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback beneficially owned an approximate 58% of the Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner. 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, 2020

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.

Making accurate estimates and assumptions is particularly difficult as the oil and natural gas industry experiences challenges resulting from negative pricing pressure from the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets. Many companies in the oil and natural gas industry have changed near term business plans in response to changing market conditions. The aforementioned circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts.

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, fair value estimates of commodity derivatives 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.

Accounts Receivable

Accounts receivable consist of receivables from oil and natural gas sales. The operators remit payment for production directly to the Partnership. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work which is required to be completed by the operator before payments are released.

The Partnership adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the rule on January 1, 2020. Accounts receivable are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Partnership when collection is deemed doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines its allowance by considering a number of factors, including the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to the Partnership, the condition of the general economy and the industry as a whole. The Partnership writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. The adoption of ASU 2016-13 did not result in a material change to the Partnership’s allowance, and no cumulative-effect adjustment was made to beginning unitholders’ equity. At December 31, 2020, the Partnership recorded an immaterial allowance for expected losses and did not record such an allowance at December 31, 2019.

Derivative Instruments

The Partnership is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations.

Revenue from Contracts with Customers

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 oil, 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. 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.

Oil and Natural Gas Properties

The Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2020 and 2019, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $10.34, $9.95 and $9.33 for the years ended December 31, 2020, 2019 and 2018, respectively. Depletion for oil and natural gas properties was $100.5 million, $78.2 million and $58.8 million for the years ended December 31, 2020, 2019 and 2018, 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. The Partnership recorded an impairment of $69.2 million on proved oil and natural gas interests for the year ended December 31, 2020. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2019 and 2018.

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 of the operator to drill; remaining lease term with the current operator; 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 $6.7 million, $6.6 million and $5.5 million, net of accumulated amortization of $4.4 million, $3.1 million and $2.2 million as of December 31, 2020, 2019 and 2018, 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 includes insignificant capitalized costs related to the Notes. The costs associated with the Notes are being netted against the Notes balances and are being amortized over the term of the Notes using the effective interest method. See Note 6—Debt for further details.

Accrued Liabilities

Accrued liabilities consist of the following:


	December 31,
	2020		2019
	(In thousands)
Interest payable	$	4,311	$	6,718
Ad valorem taxes payable	6,501		5,632
Derivatives instruments payable	7,392		—
Other	58		932
Total accrued liabilities	$	18,262	$	13,282

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, 2020, four purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (23%), Vitol Midstream Pipeline LLC (14%), Shell Trading (US) Company (“Shell Trading”) (13%), and Concho Resources (11%). 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 (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 (16%), and Trafigura Trading LLC (11%). 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 utilizing the “if-converted” method which by dividing limited partners’ interest in net income by the weighted average number of outstanding common units outstanding. The treasury-stock method is utilized to determine the dilutive effect, if any, of unvested common units granted under the Partnership’s long-term incentive plan (“LTIP”) .

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 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, 2020, 2019 and 2018, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements. See Note 9—Income Taxes for further details.

Non-controlling Interest

Non-controlling interest in the accompanying consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. When Diamondback’s relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity, tax effected, will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received

are recognized directly in equity and attributed to the controlling interest. See Note 7—Unitholders' Equity and Partnership Distributions for further discussion of the change in ownership.

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In June 2016, the Financial Accounting Standards Board (FASB) issued 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. 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.

Accounting Pronouncements Not Yet Adopted

In December 2019, the FASB issued 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. 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.

The Partnership considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed.

Revenue From Contracts With Customers

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Revenue From Contracts With Customers

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

For the years ended December 31, 2020, 2019 and 2018, any revenues recognized in the current reporting period for performance obligations satisfied in prior reporting periods was not material.

The following table disaggregates the Partnership’s total royalty income by product type:


	Year Ended December 31,
	2020		2019		2018
	(In thousands)
Oil income	$	217,859	$	264,376	$	246,922
Natural gas income	9,024		8,092		12,976
Natural gas liquids income	20,098		21,343		22,763
Total royalty income	$	246,981	$	293,811	$	282,661

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

+ Details

Acquisitions and Divestitures	12 Months Ended
Acquisitions and Divestitures	Dec. 31, 2020
Business Combinations [Abstract]
Acquisitions and Divestitures	ACQUISITIONS AND DIVESTITURES 2020 Activity During the year ended December 31, 2020, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests representing 4,948 gross (417 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $64.2 million, subject to post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility. Divestiture of Certain Non-Core Assets and Investments During 2020, the Partnership divested its equity interest in a limited partnership for approximately $10.8 million. This divestiture resulted in an immaterial loss. During the year ended December 31, 2020, the Partnership completed its divestiture of 370 net royalty acres of certain non-core Permian assets for an aggregate sale price of $38.4 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Partnership’s reserve base or depreciation, depletion and amortization rate. 2019 Activity Drop-Down Acquisition On October 1, 2019, the Partnership 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. 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 2019 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. 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. 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.

Oil and Natural Gas Interests

12 Months Ended

Dec. 31, 2020

Extractive Industries [Abstract]

Oil and Natural Gas Interests

OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:


	December 31,
	2020		2019
	(In thousands)
Oil and natural gas interests:
Subject to depletion	$	1,530,636	$	1,316,692
Not subject to depletion	1,364,906		1,551,767
Gross oil and natural gas interests	2,895,542		2,868,459
Accumulated depletion and impairment	(496,176)		(326,474)
Oil and natural gas interests, net	2,399,366		2,541,985
Land	5,688		5,688
Property, net of accumulated depletion and impairment	$	2,405,054	$	2,547,673

Balance of costs not subject to depletion:
Incurred in 2020	$	55,041
Incurred in 2019	827,680
Incurred in 2018	451,309
Incurred in 2017	30,876
Total not subject to depletion	$	1,364,906

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

The quarterly ceiling tests resulted in the Partnership recording impairment expense of $69.2 million for the year ended December 31, 2020 as a result of the decline in commodity prices. There were no impairments recorded for the years ended December 31, 2019 and 2018. In addition to commodity prices, the Partnership’s production rates, levels of proved reserves, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, the Partnership will have write-downs in subsequent quarters, which may be material.

Debt

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Debt

DEBT

Long-term debt consisted of the following as of the dates indicated:


	December 31,
	2020		2019
	(In thousands)
5.375% senior notes due 2027	$	479,938	$	500,000
Revolving credit facility	84,000		96,500
Unamortized debt issuance costs	(2,058)		(2,458)
Unamortized discount	(6,236)		(7,268)
Total long-term debt	$	555,644	$	586,774

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, which used the proceeds from the Notes Offering to pay down borrowings under its revolving credit facility. During the year ended December 31, 2020, the Partnership repurchased $20.1 million of the outstanding principal of the Notes at cash prices ranging from 97.5% to 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt. As of December 31, 2020, the remaining outstanding principal amount of the Notes totaled $479.9 million and will mature on November 1, 2027.

The Notes are senior unsecured obligations of the Partnership, are initially guaranteed on a senior unsecured basis by the Operating Company and pay interest semi-annually. Neither Diamondback nor the general partner 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 date, 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 of $580.0 million. 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. The Operating Company’s borrowing base was reaffirmed at $580.0 million by the lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of December 31, 2020, there was $496.0 million available for future borrowings under the Operating Company’s 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 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. For the years ended December 31, 2020, 2019 and 2018, the weighted average interest rate on borrowings under the Operating Company’s revolving credit facility was 2.20%, 4.51%, and 4.37%, respectively.

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, excess cash 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, 2020, the Operating Company was in compliance with all financial maintenance 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.

Unitholders’ Equity and Distributions

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Unitholders’ Equity and Distributions

UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has general partner and limited partner units. At December 31, 2020, the Partnership had a total of 65,817,281 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 beneficially owned by Diamondback, representing approximately 58% of the Partnership’s total units outstanding. Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 58% non-controlling ownership interest in the Operating Company. The Operating Company units and the Partnership’s Class B units beneficially 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).

Common Unit Offerings

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 its 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, 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.

Implementation of Common Unit Repurchase Program

On November 6, 2020, the board of directors of the Partnership’s general partner approved an expansion of the Partnership’s return of capital program with the implementation of a common unit repurchase program to acquire up to $100.0 million of the Partnership’s outstanding common units. During the year ended December 31, 2020, the Partnership repurchased approximately $24.0 million of common units under the repurchase program. As of December 31, 2020, $76.0 million remains available for use to repurchase units under the repurchase program. The common unit repurchase program is authorized to extend through December 31, 2021 and the Partnership intends to purchase common units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as

the sale of assets. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of the Partnership’s general partner at any time.

There were no changes in the number of Partnership’s Class B units during the year ended December 31, 2020.

Changes in Ownership of Consolidated Subsidiaries

The following table summarizes the ownership interest in subsidiary changes during the period:


	Year Ended December 31,
	2020		2019		2018
	(In thousands)
Net income (loss) attributable to the Partnership	$	(192,304)	$	46,281	$	143,958

Change in ownership of consolidated subsidiaries	(34,087)		(15,054)		(91,667)




Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest	$	(226,391)	$	31,227	$	52,291

During the year ended December 31, 2020, the Partnership recorded an adjustment to non-controlling interest and common unitholder equity of $34.1 million to reflect the ownership structure that was effective at December 31, 2020. These adjustments were made to reflect the changes in the ownership of the consolidated subsidiary which arose from the repurchase of subsidiary units under the 2020 repurchase program and other equity related transactions. The adjustment had no impact on earnings for the year ended December 31, 2020.

During the year ended December 31, 2019, the Partnership recorded an adjustment to non-controlling interest of $19.1 million, common unitholder equity of $15.1 million, and deferred tax asset of $4.0 million to reflect the ownership structure that was effective at December 31, 2019. These adjustments were made to reflect the changes in the ownership of the consolidated subsidiary which arose from the issuance of units that occurred during the year and other equity related transactions. The adjustment had no impact on earnings for the year ended December 31, 2019.

During the year ended December 31, 2018, the Partnership recorded an adjustment to non-controlling interest of $116.0 million, common unitholder equity of $91.7 million, and deferred tax asset of $24.4 million to reflect the ownership structure that was effective at December 31, 2018. These adjustments were made to reflect the changes in the ownership of the consolidated subsidiary which arose from the issuance of units that occurred during the year and other equity related transactions. The adjustment had no impact on earnings for the year ended December 31, 2018.

Cash Distributions

Beginning with the first quarter of 2020, the board of directors of the General Partner revised the distribution policy to provide that the Operating Company would distribute 25% of its available cash in the first and second quarters of 2020 to its unitholders (including Diamondback and the Partnership) rather than all of its available cash as it had previously done. The Operating Company’s distribution policy was further revised in October 2020 to provide for the distribution of 50% of its available cash to its unitholders beginning with the third quarter of 2020. The Partnership in turn distributes all of the available cash it receives from the Operating Company to its common unitholders. The Partnership’s available cash, and the available cash of the Operating Company, for each quarter is determined by the board of directors of the General Partner following the end of such quarter. The Operating Company’s available cash generally equals its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations, fixed charges and reserves for future operating or capital needs that the board of directors of the General Partner deems necessary or appropriate, if any. The Partnership’s available cash for each quarter generally equals its Adjusted EBITDA (which is the Partnership’s proportional share of its available cash of the Operating Company for the quarter), less cash needed for the payment of income taxes by it, if any, and the preferred distribution. Immediately prior to the revisions to the distribution policy described above, the Operating Company’s policy was to distribute all of its available cash quarterly to its unitholders. The distribution policy changes noted above were made to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet while also expanding the return of capital program through the Partnership’s common unit repurchase program.

The board of directors of the General Partner may change the distribution policies at any time. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other 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 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
February 7, 2020	Q4 2019	$	0.450	February 28, 2020	$	41,173
April 30, 2020	Q1 2020	$	0.100	May 21, 2020	$	9,175
July 29, 2020	Q2 2020	$	0.030	August 20, 2020	$	2,764
October 28, 2020	Q3 2020	$	0.100	November 19, 2020	$	9,170

Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter.

Amendment to LLC Agreement - Tax Allocation

On March 30, 2020, the Partnership, as managing member of the Operating Company, entered into the First Amendment to the Second Amended and Restated Limited Liability Company Agreement of the Operating Company to extend the remaining period of special allocations to Diamondback of the Operating Company’s income and gains over losses and deductions (but before depletion) from two to four years.

Earnings Per Common Unit

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Earnings Per Common Unit

EARNINGS PER COMMON UNIT

The net income (loss) per common unit on the consolidated statements of operations is based on the net income (loss) of the Partnership for the years ended December 31, 2020, 2019 and 2018, since this is the amount of net income (loss) that is attributable to the Partnership’s common units.

The Partnership’s net income (loss) is allocated wholly to the common units, as the General Partner does not have an economic interest. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 7—Unitholders' Equity and Partnership Distributions.

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

A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below:


	Year Ended December 31,
	2020		2019		2018
	(In thousands, except per unit amounts)
Net income (loss) attributable to the period	$	(192,304)	$	46,281	$	143,958
Less: net gain (loss) allocated to participating securities(1)	(44)		(117)		(130)
Net income (loss) attributable to common unitholders	$	(192,348)	$	46,164	$	143,828


Weighted average common units outstanding:
Basic weighted average common units outstanding	67,686		61,744		71,546
Effect of dilutive securities:
Potential common units issuable(2)	—		43		80
Diluted weighted average common units outstanding	67,686		61,787		71,626
Net income (loss) per common unit, basic	$	(2.84)	$	0.75	$	2.01
Net income (loss) per common unit, diluted	$	(2.84)	$	0.75	$	2.01

(1) Distribution equivalent rights granted to employees are considered participating securities.

(2) For the year ended December 31, 2020, no potential common units were included in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive under the treasury stock method for the periods presented but could potentially dilute basic earnings per common unit in future periods.

Income Taxes

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

The Partnership’s effective income tax rate exceeded 100% for the year ended December 31, 2020 due to the impact of recording a valuation allowance as discussed further below, and was (23.1)% and (38.0)% for the years ended December 31, 2019 and 2018, respectively. Total income tax expense for the year ended December 31, 2020 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 (loss) attributable to the non-controlling interest and the impact of recording a valuation allowance on the Partnership’s deferred tax assets. 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.

The components of the provision for income taxes for the years ended December 31, 2020, 2019 and 2018 are as follows:


	Year Ended December 31,
	2020		2019		2018
	(In thousands)
Current income tax provision (benefit):
Federal	$	—	$	—	$	—
State	—		—		151
Total current income tax provision (benefit)	—		—		151
Deferred income tax provision (benefit):
Federal	142,466		(41,582)		(72,516)
State	—		—		—
Total deferred income tax provision (benefit)	142,466		(41,582)		(72,516)
Total provision (benefit) from income taxes	$	142,466	$	(41,582)	$	(72,365)

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


	Year Ended December 31,
	2020		2019		2018
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	(10,699)	$	37,722	$	40,008
Impact of net income attributable to the pre-incorporation period	—		—		(14,279)
Impact of nontaxable noncontrolling interest	233		(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)

Change in valuation allowance	152,898		—		—
Other, net	34		(145)		(453)
Provision for (benefit from) income taxes	$	142,466	$	(41,582)	$	(72,365)

The components of the Partnership’s deferred tax assets and liabilities as of December 31, 2020 and 2019 are as follows:


	Year Ended December 31,
	2020		2019
	(In thousands)
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$	10,477	$	7,958
Investment in the Operating Company	150,127		134,272

Other	—		237
Total deferred tax assets	160,604		142,467
Valuation allowance	(160,604)		(1)
Net deferred tax assets	—		142,466




Net deferred tax assets (liabilities)	$	—	$	142,466

As of December 31, 2020, the Partnership had no net deferred tax assets or deferred tax liabilities. As of December 31, 2019, the Partnership had net deferred tax assets of approximately $142.5 million and no deferred tax liabilities. At December 31, 2020, the Partnership had federal net operating loss carryforwards of approximately $49.9 million which may be carried forward indefinitely to offset future taxable income.

As of December 31, 2020, the Partnership had a valuation allowance of approximately $160.6 million related to deferred tax assets the Partnership does not believe are more likely than not to be realized. 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. The determination to record a valuation allowance was based on management’s assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets as required by applicable accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the Partnership’s assessment resulted in application of a valuation allowance against the Partnership’s federal deferred tax assets as of March 31, 2020 and subsequent balance sheet dates within the year ended December 31, 2020. In addition, a valuation allowance was maintained against state net operating loss carryforwards not anticipated to be utilized prior to expiration.

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 basis 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 information available, 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.

The Partnership principally operates in the state of Texas. For the years ended December 31, 2020 and 2019, the Partnership did not accrue any state income tax expenses 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, 2020, the Partnership did not have any significant uncertain tax positions requiring recognition in the financial statements. In addition to the 2020 and 2019 tax years, our 2017 and 2018 tax years, periods during which we were organized as a pass-through entity for income tax purposes, remain open to examination by tax authorities.The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. This legislation included a number of provisions applicable to U.S. income taxes for corporations, including providing for carryback of certain net operating losses, accelerated refund of minimum tax credits, and modifications to the rules limiting the deductibility of business interest expense. The Partnership has considered the impact of this legislation in the period of enactment and concluded there was not a material impact to the Partnership’s current or deferred income tax balances.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References + Details

Derivatives

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES

All derivative financial instruments are recorded at fair value. The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

Commodity Contracts

During 2020, the Partnership used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. Under the Partnership’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Partnership and when the settlement price is above the ceiling price, the Partnership is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

The Partnership’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing).

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk. The Partnership’s counterparties are all participants in the amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Partnership is not required to post any collateral. The Partnership’s counterparties have been determined to have an acceptable credit risk; therefore, the Partnership does not require collateral from its counterparties.

As of December 31, 2020, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

Collars

Settlement Month

Settlement Year

Type of Contract

Bbls/Mcf Per Day

Index

Weighted Average Floor Price

Weighted Average Ceiling Price

OIL

Jan. - Mar.

2021

Collars

12,000

WTI Cushing

$30.83

$43.96

Apr. - Dec.

2021

Collars

10,000

WTI Cushing

$30.00

$43.05

Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 11—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:


	Year Ended December 31,
	2020
	(In thousands)
Gain (loss) on derivative instruments	$	(63,591)
Net cash payments on derivatives	$	(36,998)

The Partnership did not have any derivatives prior to February 2020.

Fair Value Measurements

12 Months Ended

Dec. 31, 2020

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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Partnership’s derivative instruments and investment. The Partnership measured its previously outstanding investment utilizing the fair value option, and as such the investment was classified as Level 1 in the fair value hierarchy, and included in other assets on the consolidated balance sheets at December 31, 2019. The fair values of the Partnership’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Partnership’s consolidated balance sheets as of December 31, 2020 and December 31, 2019. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	2,340	$	—	$	2,340	$	2,340	$	—



Liabilities:
Current:
Derivative instruments	$	—	$	28,933	$	—	$	28,933	$	2,340	$	26,593


	As of December 31, 2019
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:


Non-current:
Investment	$	19,357	$	—	$	—	$	19,357	$	—	$	19,357

The Partnership did not have any derivatives prior to February 2020.

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, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Debt:
Revolving credit facility	$	84,000	$	84,000	$	96,500	$	96,500
5.375% senior notes due 2027(1)	$	471,644	$	501,439	$	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 Notes was determined using the December 31, 2020 quoted market price, a Level 1 classification in the fair value hierarchy.

Fair Value of Financial Assets

The Partnership has other financial instruments consisting of cash and cash equivalents, royalty income receivable, other current assets, accounts payable and accrued liabilities. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.

- 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

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIESThe Partnership is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary 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’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. 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, 2020
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Cash Distribution On February 19, 2021, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2020 of $0.14 per common unit, payable on March 11, 2021, to unitholders of record at the close of business on March 4, 2021.

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019
	(In thousands)
Oil and natural gas interests:
Proved	$	1,530,636	$	1,316,692
Unproved	1,364,906		1,551,767
Total oil and natural gas interests	2,895,542		2,868,459
Accumulated depletion and impairment	(496,176)		(326,474)
Net oil and natural gas interests capitalized	$	2,399,366	$	2,541,985

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,
	2020		2019		2018
	(In thousands)
Acquisition costs:
Proved properties	$	56,169	$	833,221	$	497,766
Unproved properties	9,509		318,525		115,491
Total	$	65,678	$	1,151,746	$	613,257

Results of Operations from Oil and Natural Gas Producing Activities

Substantially all of the Partnership’s producing activities are from oil and natural gas activities and are included in the Consolidated Statements of Operations above.

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2020, 2019 and 2018 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, 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
Purchase of reserves in place	491	113	507
Extensions and discoveries	15,415	4,424	23,982
Revisions of previous estimates	(6,685)	763	11,043
Divestitures	(155)	(63)	(370)
Production	(5,956)	(1,848)	(11,486)
As of December 31, 2020	57,530	21,953	119,450

Proved Developed Reserves:
December 31, 2018	29,526	7,965	49,681
December 31, 2019	40,857	14,994	80,737
December 31, 2020	40,220	16,724	93,617

Proved Undeveloped Reserves:
December 31, 2018	12,352	3,027	11,916
December 31, 2019	13,563	3,570	15,037
December 31, 2020	17,310	5,229	25,833

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, 2020, the Partnership’s extensions and discoveries of 23,836 MBOE resulted primarily from the drilling of 652 new wells and from 299 new proved undeveloped locations added. The Partnership’s negative revisions of previous estimated quantities of 4,082 MBOE were due to negative price revisions and PUD downgrades. 114 MBOE of PUDs were downgraded from non-operated properties and 804 MBOE of PUDs were downgraded from Diamondback-operated properties, with the Diamondback-operated downgrades due to changes in the development plan and optimization of the inventory. The purchase of reserves in place of 689 MBOE was due to multiple acquisitions of certain mineral and royalty interests.

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.

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, 2020, 2019 and 2018:


	December 31,
	2020		2019		2018
	(In thousands)
Future cash inflows	$	2,460,052	$	3,218,257	$	2,962,386
Future production taxes	(181,067)		(237,181)		(200,079)
Future income tax expense	(22,993)		(150,373)		(273,643)
Future net cash flows	2,255,992		2,830,703		2,488,664
10% discount to reflect timing of cash flows	(1,232,398)		(1,512,315)		(1,349,282)
Standardized measure of discounted future net cash flows	$	1,023,594	$	1,318,388	$	1,139,382

The following table presents the weighted average first-day-of–the-month prices for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows:


	December 31,
	2020		2019		2018


Oil (per Bbl)	$	37.61	$	52.86	$	61.46
Natural gas (per Mcf)	$	0.34	$	0.51	$	1.84
Natural gas liquids (per Bbl)	$	11.65	$	15.79	$	25.04

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


	December 31,
	2020		2019		2018
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	1,318,388	$	1,139,382	$	625,348
Purchase of minerals in place	10,781		339,814		180,990
Divestiture of reserves	(3,481)		—		—
Sales of oil and natural gas, net of production costs	(227,137)		(274,735)		(266,055)
Extensions and discoveries	280,486		330,097		423,540
Net changes in prices and production costs	(465,582)		(301,182)		187,592
Revisions of previous quantity estimates	(87,614)		(114,409)		52,487
Net changes in income taxes	59,754		56,502		(123,804)
Accretion of discount	138,901		126,650		62,867
Net changes in timing of production and other	(902)		16,269		(3,583)
Standardized measure of discounted future net cash flows at the end of the period	$	1,023,594	$	1,318,388	$	1,139,382

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2020
Accounting Policies [Abstract]
Basis of Presentation	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.
Use of Estimates	Use of Estimates Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities at the date of the financial statements. Making accurate estimates and assumptions is particularly difficult as the oil and natural gas industry experiences challenges resulting from negative pricing pressure from the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets. Many companies in the oil and natural gas industry have changed near term business plans in response to changing market conditions. The aforementioned circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts. 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, fair value estimates of commodity derivatives and estimate of income taxes.
Cash and Cash Equivalents	Cash and Cash EquivalentsCash 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.
Accounts Receivable	Accounts Receivable Accounts receivable consist of receivables from oil and natural gas sales. The operators remit payment for production directly to the Partnership. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work which is required to be completed by the operator before payments are released. The Partnership adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the rule on January 1, 2020. Accounts receivable are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Partnership when collection is deemed doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines its allowance by considering a number of factors, including the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to the Partnership, the condition of the general economy and the industry as a whole. The Partnership writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. The adoption of ASU 2016-13 did not result in a material change to the Partnership’s allowance, and no cumulative-effect adjustment was made to beginning unitholders’ equity.
Derivative Instruments	Derivative Instruments The Partnership is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations.
Revenue from Contracts with Customers	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 oil, 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. 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.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2020 and 2019, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $10.34, $9.95 and $9.33 for the years ended December 31, 2020, 2019 and 2018, respectively. Depletion for oil and natural gas properties was $100.5 million, $78.2 million and $58.8 million for the years ended December 31, 2020, 2019 and 2018, 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. The Partnership recorded an impairment of $69.2 million on proved oil and natural gas interests for the year ended December 31, 2020. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2019 and 2018. 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 of the operator to drill; remaining lease term with the current operator; 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	Debt Issuance Costs Other assets include capitalized costs related to the credit facility of $6.7 million, $6.6 million and $5.5 million, net of accumulated amortization of $4.4 million, $3.1 million and $2.2 million as of December 31, 2020, 2019 and 2018, 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 includes insignificant capitalized costs related to the Notes. The costs associated with the Notes are being netted against the Notes balances and are being amortized over the term of the Notes using the effective interest method. See Note 6—Debt for further details.
Concentrations	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, 2020, four purchasers each accounted for more than 10% of royalty interest revenue: Trafigura Trading LLC (23%), Vitol Midstream Pipeline LLC (14%), Shell Trading (US) Company (“Shell Trading”) (13%), and Concho Resources (11%). 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 (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 (16%), and Trafigura Trading LLC (11%). 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 Earnings per unit applicable to limited partners is computed utilizing the “if-converted” method which by dividing limited partners’ interest in net income by the weighted average number of outstanding common units outstanding. The treasury-stock method is utilized to determine the dilutive effect, if any, of unvested common units granted under the Partnership’s long-term incentive plan (“LTIP”) .
Income Taxes	Income Taxes The Partnership uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Partnership is 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, 2020, 2019 and 2018, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements. See Note 9—Income Taxes for further details.
Non-controlling Interest	Non-controlling Interest Non-controlling interest in the accompanying consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. When Diamondback’s relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity, tax effected, will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 7—Unitholders' Equity and Partnership Distributions for further discussion of the change in ownership.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently Adopted Pronouncements In June 2016, the Financial Accounting Standards Board (FASB) issued 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. 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. Accounting Pronouncements Not Yet Adopted In December 2019, the FASB issued 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. 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. The Partnership considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed.
Revenue from Contract with Customer	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 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. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.
Fair Value Measurement, Policy	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. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis, including the Partnership’s derivative instruments and investment. The Partnership measured its previously outstanding investment utilizing the fair value option, and as such the investment was classified as Level 1 in the fair value hierarchy, and included in other assets on the consolidated balance sheets at December 31, 2019. The fair values of the Partnership’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Schedule of Accrued Liabilities

Accrued Liabilities

Accrued liabilities consist of the following:


	December 31,
	2020		2019
	(In thousands)
Interest payable	$	4,311	$	6,718
Ad valorem taxes payable	6,501		5,632
Derivatives instruments payable	7,392		—
Other	58		932
Total accrued liabilities	$	18,262	$	13,282

Revenue From Contracts With Customers (Tables)

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table disaggregates the Partnership’s total royalty income by product type:


	Year Ended December 31,
	2020		2019		2018
	(In thousands)
Oil income	$	217,859	$	264,376	$	246,922
Natural gas income	9,024		8,092		12,976
Natural gas liquids income	20,098		21,343		22,763
Total royalty income	$	246,981	$	293,811	$	282,661

Oil and Natural Gas Interests (Tables)

12 Months Ended

Dec. 31, 2020

Extractive Industries [Abstract]

Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities

Oil and natural gas interests include the following:


	December 31,
	2020		2019
	(In thousands)
Oil and natural gas interests:
Subject to depletion	$	1,530,636	$	1,316,692
Not subject to depletion	1,364,906		1,551,767
Gross oil and natural gas interests	2,895,542		2,868,459
Accumulated depletion and impairment	(496,176)		(326,474)
Oil and natural gas interests, net	2,399,366		2,541,985
Land	5,688		5,688
Property, net of accumulated depletion and impairment	$	2,405,054	$	2,547,673

Balance of costs not subject to depletion:
Incurred in 2020	$	55,041
Incurred in 2019	827,680
Incurred in 2018	451,309
Incurred in 2017	30,876
Total not subject to depletion	$	1,364,906

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


	December 31,
	2020		2019
	(In thousands)
Oil and natural gas interests:
Proved	$	1,530,636	$	1,316,692
Unproved	1,364,906		1,551,767
Total oil and natural gas interests	2,895,542		2,868,459
Accumulated depletion and impairment	(496,176)		(326,474)
Net oil and natural gas interests capitalized	$	2,399,366	$	2,541,985

Debt (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Schedule of Maturities of Long-Term Debt

Long-term debt consisted of the following as of the dates indicated:


	December 31,
	2020		2019
	(In thousands)
5.375% senior notes due 2027	$	479,938	$	500,000
Revolving credit facility	84,000		96,500
Unamortized debt issuance costs	(2,058)		(2,458)
Unamortized discount	(6,236)		(7,268)
Total long-term debt	$	555,644	$	586,774

Schedule of Financial Covenants


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

Unitholders’ Equity and Distributions (Tables)

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Schedule of Change in Ownership Interest

The following table summarizes the ownership interest in subsidiary changes during the period:


	Year Ended December 31,
	2020		2019		2018
	(In thousands)
Net income (loss) attributable to the Partnership	$	(192,304)	$	46,281	$	143,958

Change in ownership of consolidated subsidiaries	(34,087)		(15,054)		(91,667)




Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest	$	(226,391)	$	31,227	$	52,291

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 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
February 7, 2020	Q4 2019	$	0.450	February 28, 2020	$	41,173
April 30, 2020	Q1 2020	$	0.100	May 21, 2020	$	9,175
July 29, 2020	Q2 2020	$	0.030	August 20, 2020	$	2,764
October 28, 2020	Q3 2020	$	0.100	November 19, 2020	$	9,170

Earnings Per Common Unit (Tables)

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Schedule of Basic and Diluted Net Income Per Common Unit

A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below:


	Year Ended December 31,
	2020		2019		2018
	(In thousands, except per unit amounts)
Net income (loss) attributable to the period	$	(192,304)	$	46,281	$	143,958
Less: net gain (loss) allocated to participating securities(1)	(44)		(117)		(130)
Net income (loss) attributable to common unitholders	$	(192,348)	$	46,164	$	143,828


Weighted average common units outstanding:
Basic weighted average common units outstanding	67,686		61,744		71,546
Effect of dilutive securities:
Potential common units issuable(2)	—		43		80
Diluted weighted average common units outstanding	67,686		61,787		71,626
Net income (loss) per common unit, basic	$	(2.84)	$	0.75	$	2.01
Net income (loss) per common unit, diluted	$	(2.84)	$	0.75	$	2.01

(1) Distribution equivalent rights granted to employees are considered participating securities.

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020, 2019 and 2018 are as follows:


	Year Ended December 31,
	2020		2019		2018
	(In thousands)
Current income tax provision (benefit):
Federal	$	—	$	—	$	—
State	—		—		151
Total current income tax provision (benefit)	—		—		151
Deferred income tax provision (benefit):
Federal	142,466		(41,582)		(72,516)
State	—		—		—
Total deferred income tax provision (benefit)	142,466		(41,582)		(72,516)
Total provision (benefit) from income taxes	$	142,466	$	(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,
	2020		2019		2018
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	(10,699)	$	37,722	$	40,008
Impact of net income attributable to the pre-incorporation period	—		—		(14,279)
Impact of nontaxable noncontrolling interest	233		(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)

Change in valuation allowance	152,898		—		—
Other, net	34		(145)		(453)
Provision for (benefit from) income taxes	$	142,466	$	(41,582)	$	(72,365)

Schedule of Deferred Tax Assets and Liabilities

The components of the Partnership’s deferred tax assets and liabilities as of December 31, 2020 and 2019 are as follows:


	Year Ended December 31,
	2020		2019
	(In thousands)
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$	10,477	$	7,958
Investment in the Operating Company	150,127		134,272

Other	—		237
Total deferred tax assets	160,604		142,467
Valuation allowance	(160,604)		(1)
Net deferred tax assets	—		142,466




Net deferred tax assets (liabilities)	$	—	$	142,466

Derivatives (Tables)

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivative instruments

As of December 31, 2020, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

Collars

Settlement Month

Settlement Year

Type of Contract

Bbls/Mcf Per Day

Index

Weighted Average Floor Price

Weighted Average Ceiling Price

OIL

Jan. - Mar.

2021

Collars

12,000

WTI Cushing

$30.83

$43.96

Apr. - Dec.

2021

Collars

10,000

WTI Cushing

$30.00

$43.05

Summary of derivative contract gains and losses included in the consolidated statements of operations

The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:


	Year Ended December 31,
	2020
	(In thousands)
Gain (loss) on derivative instruments	$	(63,591)
Net cash payments on derivatives	$	(36,998)

The Partnership did not have any derivatives prior to February 2020.

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5624163-113959

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5580258-113959

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41620-113959

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5579245-113959

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41638-113959

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41678-113959

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41641-113959

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5624171-113959

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5579240-113959

+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Fair Value, Assets Measured on Recurring and Nonrecurring Basis


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	2,340	$	—	$	2,340	$	2,340	$	—



Liabilities:
Current:
Derivative instruments	$	—	$	28,933	$	—	$	28,933	$	2,340	$	26,593


	As of December 31, 2019
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:


Non-current:
Investment	$	19,357	$	—	$	—	$	19,357	$	—	$	19,357

Offsetting Liabilities


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	2,340	$	—	$	2,340	$	2,340	$	—



Liabilities:
Current:
Derivative instruments	$	—	$	28,933	$	—	$	28,933	$	2,340	$	26,593


	As of December 31, 2019
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:


Non-current:
Investment	$	19,357	$	—	$	—	$	19,357	$	—	$	19,357

Offsetting Assets


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	2,340	$	—	$	2,340	$	2,340	$	—



Liabilities:
Current:
Derivative instruments	$	—	$	28,933	$	—	$	28,933	$	2,340	$	26,593


	As of December 31, 2019
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:


Non-current:
Investment	$	19,357	$	—	$	—	$	19,357	$	—	$	19,357

Fair Value Consolidated Balance Sheets

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


	December 31, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Debt:
Revolving credit facility	$	84,000	$	84,000	$	96,500	$	96,500
5.375% senior notes due 2027(1)	$	471,644	$	501,439	$	490,274	$	521,100

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

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

12 Months Ended

Dec. 31, 2020

Extractive Industries [Abstract]

Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities

Oil and natural gas interests include the following:


	December 31,
	2020		2019
	(In thousands)
Oil and natural gas interests:
Subject to depletion	$	1,530,636	$	1,316,692
Not subject to depletion	1,364,906		1,551,767
Gross oil and natural gas interests	2,895,542		2,868,459
Accumulated depletion and impairment	(496,176)		(326,474)
Oil and natural gas interests, net	2,399,366		2,541,985
Land	5,688		5,688
Property, net of accumulated depletion and impairment	$	2,405,054	$	2,547,673

Balance of costs not subject to depletion:
Incurred in 2020	$	55,041
Incurred in 2019	827,680
Incurred in 2018	451,309
Incurred in 2017	30,876
Total not subject to depletion	$	1,364,906

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


	December 31,
	2020		2019
	(In thousands)
Oil and natural gas interests:
Proved	$	1,530,636	$	1,316,692
Unproved	1,364,906		1,551,767
Total oil and natural gas interests	2,895,542		2,868,459
Accumulated depletion and impairment	(496,176)		(326,474)
Net oil and natural gas interests capitalized	$	2,399,366	$	2,541,985

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,
	2020		2019		2018
	(In thousands)
Acquisition costs:
Proved properties	$	56,169	$	833,221	$	497,766
Unproved properties	9,509		318,525		115,491
Total	$	65,678	$	1,151,746	$	613,257

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, 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
Purchase of reserves in place	491	113	507
Extensions and discoveries	15,415	4,424	23,982
Revisions of previous estimates	(6,685)	763	11,043
Divestitures	(155)	(63)	(370)
Production	(5,956)	(1,848)	(11,486)
As of December 31, 2020	57,530	21,953	119,450

Proved Developed Reserves:
December 31, 2018	29,526	7,965	49,681
December 31, 2019	40,857	14,994	80,737
December 31, 2020	40,220	16,724	93,617

Proved Undeveloped Reserves:
December 31, 2018	12,352	3,027	11,916
December 31, 2019	13,563	3,570	15,037
December 31, 2020	17,310	5,229	25,833

Standardized Measure of Discounted Future Net Cash Flows


	December 31,
	2020		2019		2018
	(In thousands)
Future cash inflows	$	2,460,052	$	3,218,257	$	2,962,386
Future production taxes	(181,067)		(237,181)		(200,079)
Future income tax expense	(22,993)		(150,373)		(273,643)
Future net cash flows	2,255,992		2,830,703		2,488,664
10% discount to reflect timing of cash flows	(1,232,398)		(1,512,315)		(1,349,282)
Standardized measure of discounted future net cash flows	$	1,023,594	$	1,318,388	$	1,139,382

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

The following table presents the weighted average first-day-of–the-month prices for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows:


	December 31,
	2020		2019		2018


Oil (per Bbl)	$	37.61	$	52.86	$	61.46
Natural gas (per Mcf)	$	0.34	$	0.51	$	1.84
Natural gas liquids (per Bbl)	$	11.65	$	15.79	$	25.04

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,
	2020		2019		2018
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	1,318,388	$	1,139,382	$	625,348
Purchase of minerals in place	10,781		339,814		180,990
Divestiture of reserves	(3,481)		—		—
Sales of oil and natural gas, net of production costs	(227,137)		(274,735)		(266,055)
Extensions and discoveries	280,486		330,097		423,540
Net changes in prices and production costs	(465,582)		(301,182)		187,592
Revisions of previous quantity estimates	(87,614)		(114,409)		52,487
Net changes in income taxes	59,754		56,502		(123,804)
Accretion of discount	138,901		126,650		62,867
Net changes in timing of production and other	(902)		16,269		(3,583)
Standardized measure of discounted future net cash flows at the end of the period	$	1,023,594	$	1,318,388	$	1,139,382

- 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) - Diamondback Energy, Inc. - Viper Energy Partners LP	1 Months Ended		12 Months Ended
	Mar. 31, 2019	Jul. 31, 2018	Dec. 31, 2020
Limited Partners' Capital Account [Line Items]
Percent of general partner interest			100.00%
Percent of limited partnership interest	54.00%	59.00%	58.00%

Summary of Significant Accounting Policies - Oil and Natural Gas Properties, and Debt Issuance Costs (Details)	12 Months Ended
	Dec. 31, 2020 USD ($) $ / Boe	Dec. 31, 2019 USD ($) $ / Boe	Dec. 31, 2018 USD ($) $ / Boe
Accounting Policies [Abstract]
Allowance for credit loss		$ 0
Average depletion rate per barrel equivalent unit of production \| $ / Boe	10.34	9.95	9.33
Depletion for oil and natural gas properties	$ 100,501,000	$ 78,178,000	$ 58,830,000
Impairment of oil and gas properties	69,202,000	0	0
Debt issuance costs, net of accumulated amortizations	6,700,000	6,600,000	5,500,000
Debit issuance costs, accumulated amortization	$ 4,400,000	$ 3,100,000	$ 2,200,000

Summary of Significant Accounting Policies - Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Interest payable	$ 4,311	$ 6,718
Ad valorem taxes payable	6,501	5,632
Derivatives instruments payable	7,392	0
Other	58	932
Total accrued liabilities	$ 18,262	$ 13,282

Summary of Significant Accounting Policies - Concentrations (Details) - Customer Concentration Risk - Royalty Interest Revenue	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Trafigura Trading LLC
Concentration Risk [Line Items]
Percent of total royalty interest revenue	23.00%	27.00%	11.00%
Vitol Midstream Pipeline LLC
Concentration Risk [Line Items]
Percent of total royalty interest revenue	14.00%
Shell Trading
Concentration Risk [Line Items]
Percent of total royalty interest revenue	13.00%	12.00%	31.00%
Concho Resources, Inc
Concentration Risk [Line Items]
Percent of total royalty interest revenue	11.00%	16.00%	16.00%

Summary of Significant Accounting Policies - Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Interest or penalties associated with uncertain tax positions	$ 0	$ 0	$ 0

Revenue From Contracts With Customers (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Royalty income	$ 246,981	$ 293,811	$ 282,661
Oil income
Disaggregation of Revenue [Line Items]
Royalty income	217,859	264,376	246,922
Natural gas income
Disaggregation of Revenue [Line Items]
Royalty income	9,024	8,092	12,976
Natural gas liquids income
Disaggregation of Revenue [Line Items]
Royalty income	$ 20,098	$ 21,343	$ 22,763

- Definition

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8906-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9031-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9038-108599

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 4
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130543-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9054-108599

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130545-203045

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 924
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 11.L)
-URI http://asc.fasb.org/extlink&oid=6472922&loc=d3e499488-122856

+ Details

Acquisitions and Divestitures - 2020 Activity (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) a	Dec. 31, 2018 USD ($) a
Business Acquisition [Line Items]
Mineral properties acquired, net royalty (acres) \| a		3,585
Aggregate purchase price \| $		$ 440.4
Proceeds from sale of equity interest \| $	$ 10.8
Non-Core Permian Assets
Business Acquisition [Line Items]
Proceeds from sale of acres \| $	$ 38.4
Area of Land \| a	370
Mineral interests acquired in Permian Basin
Business Acquisition [Line Items]
Mineral properties acquired, gross acres (acres) \| a	4,948
Mineral properties acquired, net royalty (acres) \| a	417
Aggregate purchase price \| $	$ 64.2

Acquisitions and Divestitures - 2019 Activity (Details) shares in Millions, $ in Millions			1 Months Ended	12 Months Ended
	Oct. 31, 2019 a shares	Oct. 01, 2019 USD ($) a shares	Oct. 31, 2019 USD ($)	Dec. 31, 2019 USD ($) a	Dec. 31, 2018 USD ($) a
Business Acquisition [Line Items]
Mineral properties acquired, net royalty (acres) \| a					3,585
Aggregate purchase price \| $					$ 440.4
2019 Drop-Down Transaction
Business Acquisition [Line Items]
Fair value consideration of units issued in acquisition \| $		$ 497.2
Payments to acquire \| $		$ 190.2
Net royalty area (in acre) \| a		5,490
Percentage of mineral acres operated		95.00%
Percentage of average net royalty interest in acquired mineral and royalty interests		3.20%
2019 Drop-Down Transaction \| Class B Units
Business Acquisition [Line Items]
Number of units issued in acquisition (in shares) \| shares		18.3
Santa Elena Acquisition
Business Acquisition [Line Items]
Mineral properties acquired, net royalty (acres) \| a	1,366
Fair value consideration of units issued in acquisition \| $			$ 124.0
Percentage of average net royalty interest in acquired mineral and royalty interests	5.60%
Santa Elena Acquisition \| Limited Partners
Business Acquisition [Line Items]
Number of units issued in acquisition (in shares) \| shares	5.2
Other mineral interests acquired in 2019
Business Acquisition [Line Items]
Net royalty area (in acre) \| a				2,607
Mineral properties acquired, gross acres (acres) \| a				136,012
Aggregate purchase price \| $				$ 343.7

Acquisitions and Divestitures - 2018 Activity (Details) $ in Millions		12 Months Ended
	Aug. 15, 2018 USD ($) a	Dec. 31, 2020 USD ($) a	Dec. 31, 2018 USD ($) a
Business Acquisition [Line Items]
Mineral properties acquired, net royalty (acres)			3,585
Aggregate purchase price \| $			$ 440.4
Mineral interests acquired in Permian Basin
Business Acquisition [Line Items]
Mineral properties acquired, net royalty (acres)		417
Aggregate purchase price \| $		$ 64.2
Mineral properties acquired, gross acres (acres)		4,948
Mineral interests acquired in Permian Basin \| Diamondback Energy, Inc.
Business Acquisition [Line Items]
Mineral properties acquired, net royalty (acres)	1,696
Aggregate purchase price \| $	$ 175.0
Mineral properties acquired, gross acres (acres)	32,424
Percentage of mineral acres operated by affiliate	80.00%

Oil and Natural Gas Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Subject to depletion	$ 1,530,636	$ 1,316,692
Not subject to depletion	1,364,906	1,551,767
Gross oil and natural gas interests	2,895,542	2,868,459
Accumulated depletion and impairment	(496,176)	(326,474)
Oil and natural gas interests, net	2,399,366	2,541,985
Land	5,688	5,688
Property, net	2,405,054	2,547,673
Balance of costs not subject to depletion:	55,041	827,680	$ 451,309	$ 30,876
Impairment	$ 69,202	$ 0	$ 0
Minimum
Property, Plant and Equipment [Line Items]
Anticipated timing of cost inclusion in amortization calculation	5 years
Maximum
Property, Plant and Equipment [Line Items]
Anticipated timing of cost inclusion in amortization calculation	10 years

Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Line of Credit Facility [Line Items]
Unamortized debt issuance costs	$ (2,058)	$ (2,458)
Unamortized discount	(6,236)	(7,268)
Total long-term debt	555,644	586,774
Revolving credit facility
Line of Credit Facility [Line Items]
Long term debt gross	84,000	96,500
5.375% senior notes due 2027
Line of Credit Facility [Line Items]
Long term debt gross	$ 479,938	$ 500,000
Debt instrument, interest rate, stated percentage	5.375%

Debt - Additional Information (Details)		12 Months Ended
Debt - Additional Information (Details)	Oct. 16, 2019 USD ($)	Dec. 31, 2020 USD ($) redeterminations	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Jul. 20, 2018 USD ($)
Line of Credit Facility [Line Items]
Proceeds from issuance of senior long-term debt		$ 0	$ 500,000,000	$ 0
Repayments of senior notes		19,697,000	0	$ 0
Revolving Credit Facility
Line of Credit Facility [Line Items]
Long term debt gross		84,000,000	$ 96,500,000
Maximum borrowing capacity					$ 2,000,000,000.0
Current borrowing capacity		$ 580,000,000.0
Number of additional redeterminations that may be requested \| redeterminations		3
Period of redeterminations		12 months
Remaining borrowing capacity		$ 496,000,000.0
Weighted average interest rate		2.20%	4.51%	4.37%
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%
Senior Notes
Line of Credit Facility [Line Items]
Maximum issuance of unsecured debt		$ 1,000,000,000.0
5.375% senior notes due 2027
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage		5.375%
Long term debt gross		$ 479,938,000	$ 500,000,000
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
Repayments of senior notes		20,100,000
Long term debt gross		$ 479,900,000
5.375% senior notes due 2027 \| Senior Notes \| Minimum
Line of Credit Facility [Line Items]
Discount percentage		97.50%
5.375% senior notes due 2027 \| Senior Notes \| Maximum
Line of Credit Facility [Line Items]
Discount percentage		98.50%

Debt - Financial Covenants (Details)	Dec. 31, 2020 USD ($)
Maximum
Line of Credit Facility [Line Items]
Ratio of total net debt to EBITDAX, as defined in the credit agreement	4.0
Minimum
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1.0
Senior Notes
Line of Credit Facility [Line Items]
Maximum issuance of unsecured debt	$ 1,000,000,000.0
Reduction of borrowing base	25.00%

Unitholders’ Equity and Distributions - Additional Information (Details) - USD ($)	1 Months Ended		3 Months Ended	12 Months Ended
	Mar. 31, 2019	Jul. 31, 2018	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Feb. 19, 2021	Nov. 06, 2020	Sep. 30, 2020	Jun. 30, 2020
Limited Partners' Capital Account [Line Items]
Amount of shares repurchased				$ 24,026,000
Change in ownership of consolidated subsidiaries, net				$ 0	$ 4,001,000	$ 24,367,000
Dedication period remaining			2 years	4 years
Revolving credit facility
Limited Partners' Capital Account [Line Items]
Repayments of debt		$ 361,500,000
Cash Distribution
Limited Partners' Capital Account [Line Items]
Percentage of cash available			25.00%						50.00%	25.00%
Cash distributions, distribution period after quarter end				60 days
Diamondback Energy, Inc. \| Viper Energy Partners LP
Limited Partners' Capital Account [Line Items]
Percent of limited partnership interest	54.00%	59.00%		58.00%
Percentage by noncontrolling owners				58.00%
Common Units
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units issued (in shares)				65,817,281	67,805,707
Limited partners' capital account, units outstanding (in shares)				65,817,281	67,805,707
Authorized amount in repurchase program								$ 100,000,000.0
Amount of shares repurchased				$ 24,000,000.0
Remaining authorized repurchase amount				$ 76,000,000.0
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	$ 340,600,000	$ 303,100,000
Common Units \| Over-Allotment Option
Limited Partners' Capital Account [Line Items]
Units issued in public offering (in shares)	1,425,000	1,080,000
Common Units \| Diamondback Energy, Inc.
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units outstanding (in shares)				731,500
Class B Units
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units issued (in shares)				90,709,946	90,709,946
Limited partners' capital account, units outstanding (in shares)				90,709,946	90,709,946		90,709,946
Change in ownership of consolidated subsidiaries, net				$ 0
Class B Units \| Diamondback Energy, Inc.
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units outstanding (in shares)				90,709,946
Operating Company Units \| Diamondback Energy, Inc.
Limited Partners' Capital Account [Line Items]
Limited partners' capital account, units outstanding (in shares)				90,709,946

Unitholders’ Equity and Distributions - Ownership Interest in Subsidiary Changes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to the period	$ (192,304)	$ 46,281	$ 143,958
Limited Partners
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to the period	(192,304)	46,281	143,958
Change in ownership of consolidated subsidiaries due to purchase of subsidiary shares in 2020 and 2019 offering	(34,087)	(15,054)	(91,667)
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest	$ (226,391)	$ 31,227	$ 52,291

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121641772&loc=SL7669619-108580

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8924-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 11
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22694-107794

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(22))
-URI http://asc.fasb.org/extlink&oid=120399700&loc=SL114874048-224260

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 11
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22694-107794

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721683-107760

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22595-107794

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1B
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121641772&loc=SL7669625-108580

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(18))
-URI http://asc.fasb.org/extlink&oid=120400993&loc=SL114874131-224263

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(20))
-URI http://asc.fasb.org/extlink&oid=120395209&loc=SL114868664-224227

Reference 13: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=121586364&loc=d3e3602-108585

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22499-107794

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22663-107794

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=75031198&loc=d3e14064-108612

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8906-108599

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22583-107794

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-URI http://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 60B
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121326447&loc=SL5780133-109256

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=114001798&loc=d3e33918-111571

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22658-107794

+ Details

Unitholders’ Equity and Distributions - Schedule of Partnership Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands												12 Months Ended
	Oct. 28, 2020	Jul. 29, 2020	Apr. 30, 2020	Feb. 07, 2020	Oct. 25, 2019	Jul. 28, 2019	Apr. 25, 2019	Jan. 30, 2019	Oct. 23, 2018	Jul. 27, 2018	Apr. 05, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Distribution Made to Limited Partner [Line Items]
Amount Distributed to Diamondback												$ 45,630	$ 107,074	$ 98,333
Cash Distribution
Distribution Made to Limited Partner [Line Items]
Cash distribution, amount per Common Unit (in USD per share)	$ 0.100	$ 0.030	$ 0.100	$ 0.450	$ 0.460	$ 0.470	$ 0.380	$ 0.510	$ 0.580	$ 0.600	$ 0.480
Amount Distributed to Diamondback	$ 9,170	$ 2,764	$ 9,175	$ 41,173	$ 33,668	$ 34,400	$ 27,817	$ 37,326	$ 42,447	$ 43,901	$ 35,112

Earnings Per Common Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share [Abstract]
Net income (loss) attributable to the period	$ (192,304)	$ 46,281	$ 143,958
Less: net gain (loss) allocated to participating securities	(44)	(117)	(130)
Net income (loss) attributable to common unitholders	$ (192,348)	$ 46,164	$ 143,828
Basic weighted average common units outstanding (in shares)	67,686,000	61,744,000	71,546,000
Effect of dilutive securities:
Potential common units issuable (in shares)	0	43,000	80,000
Diluted weighted average common units outstanding (in shares)	67,686,000	61,787,000	71,626,000
Net income per common unit, basic (dollars per shares)	$ (2.84)	$ 0.75	$ 2.01
Net income per common unit, diluted (dollars per shares)	$ (2.84)	$ 0.75	$ 2.01
Antidilutive securities, restricted stock units (in shares)	0

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Effective income tax rates	100.00%	(23.10%)	(38.00%)
Deferred tax assets or deferred tax liabilities, net	$ 0	$ 142,466,000
Net deferred tax assets		142,466,000
Deferred tax liabilities		0
Federal net operating loss carryforwards	49,900,000
Valuation allowance	160,604,000	1,000
Income tax benefit	0	42,424,000	$ 72,787,000
Income tax expense	$ 0	$ 0	$ 151,000

Income Taxes - Components of Provision for Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current income tax provision (benefit):
Federal	$ 0	$ 0	$ 0
State	0	0	151,000
Total current income tax provision (benefit)	0	0	151,000
Deferred income tax provision (benefit):
Federal	142,466,000	(41,582,000)	(72,516,000)
State	0	0	0
Total deferred income tax provision (benefit)	142,466,000	(41,582,000)	(72,516,000)
Total provision (benefit) from income taxes	$ 142,466,000	$ (41,582,000)	$ (72,365,000)

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Income Taxes - Reconciliation of Statutory Federal Income tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the federal statutory rate (21%)	$ (10,699)	$ 37,722	$ 40,008
Impact of net income attributable to the pre-incorporation period	0	0	(14,279)
Impact of nontaxable noncontrolling interest	233	(36,735)	(24,973)
State income tax expense (benefit), net of federal tax effect	0	0	119
Deferred taxes related to change in tax status	0	(42,424)	(72,787)
Change in valuation allowance	152,898	0	0
Other, net	34	(145)	(453)
Total provision (benefit) from income taxes	$ 142,466	$ (41,582)	$ (72,365)

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets:
Net operating loss and interest expense carryforwards (indefinite life carryforward)	$ 10,477	$ 7,958
Investment in the Operating Company	150,127	134,272
Other	0	237
Total deferred tax assets	160,604	142,467
Valuation allowance	(160,604)	(1)
Net deferred tax assets		142,466
Net deferred tax assets (liabilities)	$ 0	$ 142,466

Derivatives - Open Derivative Positions (Details) - OIL - WTI Cushing - Collars bbl in Thousands	12 Months Ended
	Dec. 31, 2020 $ / bbl bbl
Jan. - Mar.
Derivative [Line Items]
Volume (Bbls) \| bbl	12
Floor price (per Bbl)	30.83
Ceiling price (per Bbl)	43.96
Apr. - Dec.
Derivative [Line Items]
Volume (Bbls) \| bbl	10
Floor price (per Bbl)	30.00
Ceiling price (per Bbl)	43.05

Derivatives - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gain (loss) on derivative instruments	$ (63,591)	$ 0	$ 0
Net cash payments on derivatives	$ (36,998)	$ 0	$ 0

Fair Value Measurements - Recurring Measurements (Details) - USD ($)	Dec. 31, 2020	Jan. 31, 2020	Dec. 31, 2019
Current:
Derivative instruments	$ 26,593,000		$ 0
Fair Value, Recurring \| Derivative instruments
Current:
Total Gross Fair Value	2,340,000
Gross Amounts Offset in Balance Sheet	2,340,000
Derivative instruments	0
Current:
Total Gross Fair Value	28,933,000
Gross Amounts Offset in Balance Sheet	2,340,000
Derivative instruments	26,593,000
Derivative assets		$ 0
Derivative liabilities		$ 0
Fair Value, Recurring \| Investment
Non-current:
Total Gross Fair Value			19,357,000
Gross Amounts Offset in Balance Sheet			0
Derivative instruments			19,357,000
Fair Value, Recurring \| Fair Value, Inputs, Level 1 \| Derivative instruments
Current:
Total Gross Fair Value	0
Current:
Total Gross Fair Value	0
Fair Value, Recurring \| Fair Value, Inputs, Level 1 \| Investment
Non-current:
Total Gross Fair Value			19,357,000
Fair Value, Recurring \| Level 2 \| Derivative instruments
Current:
Total Gross Fair Value	2,340,000
Current:
Total Gross Fair Value	28,933,000
Fair Value, Recurring \| Level 2 \| Investment
Non-current:
Total Gross Fair Value			0
Fair Value, Recurring \| Level 3 \| Derivative instruments
Current:
Total Gross Fair Value	0
Current:
Total Gross Fair Value	$ 0
Fair Value, Recurring \| Level 3 \| Investment
Non-current:
Total Gross Fair Value			$ 0

Fair Value Measurements - Fair Value of Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
5.375% senior notes due 2027
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated percentage	5.375%
Carrying Value \| Fair Value, Nonrecurring \| Revolving credit facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value	$ 84,000	$ 96,500
Carrying Value \| Fair Value, Nonrecurring \| 5.375% senior notes due 2027
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value	471,644	490,274
Fair Value \| Fair Value, Nonrecurring \| Revolving credit facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value	84,000	96,500
Fair Value \| Fair Value, Nonrecurring \| 5.375% senior notes due 2027
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value	$ 501,439	$ 521,100

Subsequent Events (Details) - Cash Distribution - $ / shares	Feb. 19, 2021	Oct. 28, 2020	Jul. 29, 2020	Apr. 30, 2020	Feb. 07, 2020	Oct. 25, 2019	Jul. 28, 2019	Apr. 25, 2019	Jan. 30, 2019	Oct. 23, 2018	Jul. 27, 2018	Apr. 05, 2018
Subsequent Event [Line Items]
Cash distribution, amount per Common Unit (in USD per share)		$ 0.100	$ 0.030	$ 0.100	$ 0.450	$ 0.460	$ 0.470	$ 0.380	$ 0.510	$ 0.580	$ 0.600	$ 0.480
Subsequent Event
Subsequent Event [Line Items]
Cash distribution, amount per Common Unit (in USD per share)	$ 0.14

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, 2020	Dec. 31, 2019
Oil and natural gas interests:
Proved	$ 1,530,636	$ 1,316,692
Unproved	1,364,906	1,551,767
Total oil and natural gas interests	2,895,542	2,868,459
Accumulated depletion and impairment	(496,176)	(326,474)
Net oil and natural gas interests capitalized	$ 2,399,366	$ 2,541,985

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved properties	$ 56,169	$ 833,221	$ 497,766
Unproved properties	9,509	318,525	115,491
Total	$ 65,678	$ 1,151,746	$ 613,257

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, 2020 Boe well bbl Mcf	Dec. 31, 2019 Boe well bbl Mcf	Dec. 31, 2018 Boe well bbl Mcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Partnership’s extensions and discoveries (Energy) \| Boe	23,836	17,091	19,549
Oil and gas, development well drilled, net productive, number \| well	652	829	133
New proved undeveloped location \| well	299	97	138
Revision of previous estimate (Energy) \| Boe	(4,082)	(5,337)	2,342
Purchase of reserves (Energy) \| Boe	689	21,914	9,305
MBOE of PUDs downgraded from non-operated properties \| Boe	114
MBOE of PUDs downgraded due to changes in the development plan and optimization of the inventory \| Boe	804
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	54,420	41,878	25,885
Purchase of reserves in place	491	12,949	5,394
Extensions and discoveries	15,415	11,526	13,858
Revisions of previous estimates	(6,685)	(6,810)	1,140
Divestitures	(155)
Production	(5,956)	(5,123)	(4,399)
End of period	57,530	54,420	41,878
Proved developed reserves (Volume)	40,220	40,857	29,526
Proved undeveloped reserve (Volume)	17,310	13,563	12,352
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	18,564	10,992	6,295
Purchase of reserves in place	113	4,895	1,163
Extensions and discoveries	4,424	3,095	3,359
Revisions of previous estimates	763	1,041	1,108
Divestitures	(63)
Production	(1,848)	(1,459)	(933)
End of period	21,953	18,564	10,992
Proved developed reserves (Volume)	16,724	14,994	7,965
Proved undeveloped reserve (Volume)	5,229	3,570	3,027
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period \| Mcf	95,774	61,597	36,395
Purchase of reserves in place \| Mcf	507	24,423	16,486
Extensions and discoveries \| Mcf	23,982	14,822	13,992
Revisions of previous estimates \| Mcf	11,043	2,589	564
Divestitures \| Mcf	(370)
Production \| Mcf	(11,486)	(7,657)	(5,840)
End of period \| Mcf	119,450	95,774	61,597
Proved developed reserves (Volume) \| Mcf	93,617	80,737	49,681
Proved undeveloped reserve (Volume) \| Mcf	25,833	15,037	11,916

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Future cash inflows	$ 2,460,052	$ 3,218,257	$ 2,962,386
Future production taxes	(181,067)	(237,181)	(200,079)
Future income tax expense	(22,993)	(150,373)	(273,643)
Future net cash flows	2,255,992	2,830,703	2,488,664
10% discount to reflect timing of cash flows	(1,232,398)	(1,512,315)	(1,349,282)
Standardized measure of discounted future net cash flows	$ 1,023,594	$ 1,318,388	$ 1,139,382	$ 625,348

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, 2020 $ / bbl $ / Mcf	Dec. 31, 2019 $ / bbl $ / Mcf	Dec. 31, 2018 $ / bbl $ / Mcf
Oil
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Unweighted arithmetic average first-day-of-the-month prices	37.61	52.86	61.46
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	0.34	0.51	1.84
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	11.65	15.79	25.04

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Standardized measure of discounted future net cash flows at the beginning of the period	$ 1,318,388	$ 1,139,382	$ 625,348
Purchase of minerals in place	10,781	339,814	180,990
Divestiture of reserves	(3,481)	0	0
Sales of oil and natural gas, net of production costs	(227,137)	(274,735)	(266,055)
Extensions and discoveries	280,486	330,097	423,540
Net changes in prices and production costs	(465,582)	(301,182)	187,592
Revisions of previous quantity estimates	(87,614)	(114,409)	52,487
Net changes in income taxes	59,754	56,502	(123,804)
Accretion of discount	138,901	126,650	62,867
Net changes in timing of production and other	(902)	16,269	(3,583)
Standardized measure of discounted future net cash flows at the end of the period	$ 1,023,594	$ 1,318,388	$ 1,139,382