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

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

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

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue	$ 288,820	$ 172,033	$ 79,146
Lease bonus income	2,920	11,764	0
Lease bonus income - related party	3,109	106	309
Other operating income	130	0	0
Costs and expenses:
Production and ad valorem taxes	19,048	10,608	5,544
Depletion	58,830	40,519	29,820
Impairment	0	0	47,469
General and administrative expenses	7,955	6,296	5,209
Total costs and expenses	85,833	58,212	88,457
Income (loss) from operations	202,987	113,821	(9,311)
Other income (expense):
Interest expense, net	(13,849)	(3,164)	(2,455)
Loss on revaluation of investment	(550)	0	0
Other income, net	1,924	821	867
Total other income (expense), net	(12,475)	(2,343)	(1,588)
Income (loss) before income taxes	190,512	111,478	(10,899)
Benefit from income taxes	(72,365)	0	0
Net income (loss)	262,877	111,478	(10,899)
Net income attributable to non-controlling interest	118,919	0	0
Net income (loss) attributable to Viper Energy Partners LP	$ 143,958	$ 111,478	$ (10,899)
Net income (loss) attributable to common limited partners per unit:
Basic (dollars per unit)	$ 2.01	$ 1.07	$ (0.13)
Diluted (dollars per unit)	$ 2.01	$ 1.07	$ (0.13)
Weighted average number of common limited partner units outstanding:
Basic (in units)	71,546	104,318	83,081
Diluted (in units)	71,626	104,383	83,081
Royalty [Member]
Revenue	$ 282,661	$ 160,163	$ 78,837
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Costs and expenses:
Gathering and transportation	$ 0	$ 789	$ 415

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

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

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Presentation	ORGANIZATION AND BASIS OF PRESENTATION Organization Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”), on February 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin and Eagle Ford Shale. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of Viper Energy Partners LP and its consolidated subsidiary, Viper Energy Partners LLC. As of December 31, 2018, a wholly-owned subsidiary of Diamondback, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback had an approximate 59% limited partner interest in the Partnership. Diamondback owns and controls the General Partner. Recapitalization, Tax Status Election and Related Transactions On May 9, 2018, we filed an election with the Internal Revenue Service to change the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on that date the Partnership (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, or Operating Company, (iii) amended and restated its existing registration rights agreement with Diamondback and (iv) entered into an exchange agreement with Diamondback, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback delivered and assigned to the Partnership the 73,150,000 common units Diamondback owned in exchange for (i) 73,150,000 of the Partnership’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018, or Recapitalization Agreement. Immediately following that exchange, the Partnership continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and Diamondback owned the remaining approximately 64% of the outstanding units issued by the Operating Company. The Operating Company units and the Partnership’s Class B units owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit). On May 10, 2018, the change in the Partnership’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to the Partnership in respect of its general partner interest and (ii) Diamondback made a cash capital contribution of $1.0 million to the Partnership in respect of the Class B units. Diamondback, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, Diamondback also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and Diamondback continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure was adopted to provide anticipated significant benefits to the Partnership’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018. Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation.

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities at the date of the financial statements. The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, the recoverability of costs of unevaluated properties, unit–based compensation and estimate of income taxes. Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments. Restricted Cash In 2014, the Predecessor entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The Predecessor subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matter in April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified as restricted cash. Revenue from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the operator. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index. Royalty income from oil, natural gas and natural gas liquids sales The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of our royalty income contracts. Contract balances Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded. Fair Value of Financial Instruments Our financial instruments consist of cash and cash equivalents, receivables, payables and a credit agreement. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. Oil and Natural Gas Properties The Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. At December 31, 2018 and 2017, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $9.33, $10.07 and $12.67 for the years ended December 31, 2018, 2017 and 2016, respectively. Depletion for oil and gas properties was $58.8 million, $40.5 million and $29.8 million for the years ended December 31, 2018, 2017 and 2016, respectively. Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write-down is required. During the year ended December 31, 2016, the Partnership recorded an impairment on proved oil and natural gas properties of $47.5 million. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2018 and 2017. Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property on an annual basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. Debt Issuance Costs Other assets include capitalized costs of $5.5 million, $4.4 million and $2.2 million, net of accumulated amortization of $2.2 million, $1.4 million and $0.8 million as of December 31, 2018, 2017 and 2016, respectively. The costs are associated with the Partnership’s credit agreement and are being amortized over the term of the credit agreement. Royalty Interest and Revenue Recognition Royalty interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when control passes to the producer. Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur any of the costs of exploration, development and operation of the property. Concentrations The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2018, three purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (US) Company (“Shell Trading”) (31%), Concho Resources, Inc. (16%) and Trafigura Trading LLC (11%). For the year ended December 31, 2017, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (47%) and RSP Permian LLC (23%). For the year ended December 31, 2016, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (57%) and RSP Permian LLC (32%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Investments The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. For the year ended December 31, 2018, the Partnership recorded a loss of $0.6 million, which then decreased the Partnership’s investment balance to $14.5 million, which is included in other assets in the accompanying consolidated balance sheets. Earnings Per Unit Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units. Unit–Based Compensation Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 7—Unit–Based Compensation. Income Taxes The Partnership uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Partnership is subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 10—Income Taxes. In addition to the 2018 tax year, the Partnership’s 2015 through 2017 tax years, during which the Partnership was organized as a pass-through entity for federal income tax purposes, remain open to examination by tax authorities. As of December 31, 2018 and 2017, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2018, 2017 and 2016, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback. Diamondback does not expect any Texas margin tax to be due for the years ended December 31, 2017 and 2016, so no amount has been provided in the accompanying financial statements. New Accounting Pronouncements Recently Adopted Pronouncements In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Partnership adopted this standard effective January 1, 2018 using the modified retrospective method. The Partnership utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standard on its total revenues, operating income and the Partnership’s consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment. In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million. In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Partnership adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows. In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of December 31, 2018, the Partnership was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. The Partnership adopted this standard effective January 1, 2019 using the modified retrospective method. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses. In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions	ACQUISITIONS 2018 Activity During the year ended December 31, 2018, the Partnership acquired mineral interests from unrelated third parties underlying 3,585 net royalty acres for an aggregate of approximately $440.4 million and, as of December 31, 2018, had mineral interests underlying 14,841 net royalty acres. The Partnership funded these acquisitions primarily with cash on hand and borrowings under its revolving credit facility. On August 15, 2018, the Partnership acquired mineral interests from Diamondback underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by Diamondback, for $175.0 million. 2017 Activity During the year ended December 31, 2017, the Partnership acquired mineral interests underlying 3,157 net royalty acres for an aggregate of approximately $343.1 million and, as of December 31, 2017, had mineral interests underlying 9,570 net royalty acres. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility, with a portion of the net proceeds from its January and July 2017 offerings of common units and with the issuance of 174,513 common units to a seller in a private placement in May 2017. 2016 Activity During the year ended December 31, 2016, the Partnership acquired mineral interests underlying 2,142 net royalty acres in 63 transactions for an aggregate of approximately $205.7 million. The Partnership funded these acquisitions primarily with borrowings under its revolving credit facility and a portion of the net proceeds from its August 2016 offering of common units.

Oil and Natural Gas Interests

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Oil and Natural Gas Interests

OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:



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

Balance of costs not subject to depletion:
Incurred in 2018	$	476,027
Incurred in 2017	284,371
Incurred in 2016	111,087
Total not subject to depletion	$	871,485

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

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

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

Debt

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt

DEBT

Credit Agreement-Wells Fargo Bank

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

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

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



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

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

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

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS Acquisition On August 15, 2018, the Partnership acquired from Diamondback mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by Diamondback, for $175.0 million. Partnership Agreement The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Partnership Agreement”), requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For each of the years ended December 31, 2018 and 2017, the General Partner allocated $2.5 million, to the Partnership. For the year ended December 31, 2016, the General Partner did not allocate any amounts to the Partnership. Advisory Services Agreement In connection with the closing of the IPO, the Partnership and General Partner entered into an advisory services agreement with Wexford Capital LP (“Wexford”) dated as of June 23, 2014 (the “Advisory Services Agreement”), under which Wexford agreed to provide the Partnership and the General Partner with general financial and strategic advisory services related to the Partnership’s business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement was terminated on November 12, 2018 with an effective date of December 31, 2018. For the years ended December 31, 2018, 2017 and 2016, the Partnership did not pay any amounts under the Advisory Services Agreement. Tax Sharing In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback. Lease Bonus During the year ended December 31, 2018, Diamondback paid the Partnership $2.5 million in lease bonus payments to extend the term of 13 leases, reflecting an average bonus of $4,149 per acre and $0.6 million in lease bonus payments for one new lease, reflecting an average bonus of $18,002 per acre. During the year ended December 31, 2017, Diamondback paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre. During the year ended December 31, 2016, Diamondback paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.

Unit-Based Compensation

12 Months Ended

Dec. 31, 2018

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

Unit-Based Compensation

UNIT–BASED COMPENSATION

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

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

Unit Options

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

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



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

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



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

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

Phantom Units

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

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



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

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

Partners' Capital and Partnership Distributions

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Partners' Capital and Partnership Distributions

UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and limited partner units. At December 31, 2018, the Partnership had a total of 51,653,956 common units and 72,418,500 Class B units issued and outstanding, of which 731,500 common units and 72,418,500 Class B units were owned by Diamondback, representing approximately 59% of the total Partnership’s units outstanding. The Operating Company units and the Partnership’s Class B units owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

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



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

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



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

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

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

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

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

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



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

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

Earnings Per Unit

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Earnings Per Unit

EARNINGS PER UNIT

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

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

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



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

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



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

Income Taxes

12 Months Ended

Dec. 31, 2018

Operating Loss Carryforwards [Line Items]

Income Tax Disclosure [Text Block]

INCOME TAXES

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

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

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

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

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



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

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



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

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



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

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

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

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

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Supplemental information on oil and natural gas operations

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

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

Capitalized oil and natural gas costs

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



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

Costs incurred in oil and natural gas activities

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



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

Results of Operations from Oil and Natural Gas Producing Activities

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



	December 31,
	2018			2017			2016
	(In thousands)
Royalty income	$	282,661		$	160,163		$	78,837
Production and ad valorem taxes	(19,048		)	(10,608		)	(5,544		)
Gathering and transportation	—			(789		)	(415		)
Depletion	(58,830		)	(40,519		)	(29,820		)
Impairment	—			—			(47,469		)
Income tax expense	(422		)	—			—
Results of operations from oil, natural gas and natural gas liquids	$	204,361		$	108,247		$	(4,411	)

Oil and Natural Gas Reserves

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

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

The changes in estimated proved reserves are as follows:



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

Proved Developed Reserves:
December 31, 2016	12,332		3,247		15,933
December 31, 2017	18,788		4,536		29,256
December 31, 2018	29,526		7,965		49,681

Proved Undeveloped Reserves:
December 31, 2016	9,012		2,329		11,158
December 31, 2017	7,097		1,759		7,139
December 31, 2018	12,352		3,027		11,916

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

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

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

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

Standardized Measure of Discounted Future Net Cash Flows

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

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



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

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



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

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



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

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL DATA (Unaudited)



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



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

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2018
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities at the date of the financial statements. The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, the recoverability of costs of unevaluated properties, unit–based compensation and estimate of income taxes.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits.
Royalty Income Receivable	Revenue from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the operator. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index. Royalty income from oil, natural gas and natural gas liquids sales The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of our royalty income contracts. Contract balances Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.
Fair Value of Financial Instruments	Fair Value of Financial Instruments Our financial instruments consist of cash and cash equivalents, receivables, payables and a credit agreement. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments.
Oil and Natural Gas Properties	Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write-down is required. Oil and Natural Gas Properties The Partnership uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property on an annual basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves.
Debt Issuance Costs	The costs are associated with the Partnership’s credit agreement and are being amortized over the term of the credit agreement.
Royalty Interest and Revenue Recognition	Royalty Interest and Revenue Recognition Royalty interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when control passes to the producer. Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur any of the costs of exploration, development and operation of the property.
Concentrations	The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact the Partnership’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Concentrations The Partnership is subject to risk resulting from the concentration of the Partnership’s royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers.
Investments	Investments The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method.
Earnings Per Unit	Earnings Per Unit Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.
Unit-based Compensation	Unit–Based Compensation Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 7—Unit–Based Compensation.
Income Taxes	Income Taxes The Partnership uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Partnership is subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 10—Income Taxes. In addition to the 2018 tax year, the Partnership’s 2015 through 2017 tax years, during which the Partnership was organized as a pass-through entity for federal income tax purposes, remain open to examination by tax authorities. As of December 31, 2018 and 2017, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2018, 2017 and 2016, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.
New Accounting Pronouncements	New Accounting Pronouncements Recently Adopted Pronouncements In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Partnership adopted this standard effective January 1, 2018 using the modified retrospective method. The Partnership utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standard on its total revenues, operating income and the Partnership’s consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment. In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million. In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Partnership adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows. In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of December 31, 2018, the Partnership was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. The Partnership adopted this standard effective January 1, 2019 using the modified retrospective method. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. The Partnership adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on its financial position, results of operations or liquidity. In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses. In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

Oil and Natural Gas Interests (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Aggregate capitalized costs related to oil and natural gas production activities

Oil and natural gas interests include the following:



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

Balance of costs not subject to depletion:
Incurred in 2018	$	476,027
Incurred in 2017	284,371
Incurred in 2016	111,087
Total not subject to depletion	$	871,485

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



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

Unit-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

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

Schedule of valuation assumptions



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

Schedule of unit option activity

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



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

Schedule of Nonvested Performance-based Units Activity

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



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

Partners' Capital and Partnership Distributions (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Schedule of changes in common units

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



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

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



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

Distributions Made to Limited Partner, by Distribution

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



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

Earnings Per Unit (Tables)

12 Months Ended

Dec. 31, 2018

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

Schedule of basic and diluted net income per common unit



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

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



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

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Operating Loss Carryforwards [Line Items]

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

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



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

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

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



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

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

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



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

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

12 Months Ended

Dec. 31, 2018

Extractive Industries [Abstract]

Aggregate capitalized costs related to oil and natural gas production activities

Oil and natural gas interests include the following:



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

Balance of costs not subject to depletion:
Incurred in 2018	$	476,027
Incurred in 2017	284,371
Incurred in 2016	111,087
Total not subject to depletion	$	871,485

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



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

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

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



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

Results of Operations for Oil and Gas Producing Activities



	December 31,
	2018			2017			2016
	(In thousands)
Royalty income	$	282,661		$	160,163		$	78,837
Production and ad valorem taxes	(19,048		)	(10,608		)	(5,544		)
Gathering and transportation	—			(789		)	(415		)
Depletion	(58,830		)	(40,519		)	(29,820		)
Impairment	—			—			(47,469		)
Income tax expense	(422		)	—			—
Results of operations from oil, natural gas and natural gas liquids	$	204,361		$	108,247		$	(4,411	)

Changes in Estimated Proved Reserves

The changes in estimated proved reserves are as follows:



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

Proved Developed Reserves:
December 31, 2016	12,332		3,247		15,933
December 31, 2017	18,788		4,536		29,256
December 31, 2018	29,526		7,965		49,681

Proved Undeveloped Reserves:
December 31, 2016	9,012		2,329		11,158
December 31, 2017	7,097		1,759		7,139
December 31, 2018	12,352		3,027		11,916

Standardized Measure of Discounted Future Net Cash Flows



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

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

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



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

Principal Changes in Standardized Measure of Discounted Future Net Cash Flows

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



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

- 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

- Definition

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

+ References

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-Name Accounting Standards Codification
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+ Details

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

- Definition

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

+ References + Details

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES The Partnership could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Cash Distribution On January 30, 2019, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2018 of $0.51 per common unit, payable on February 25, 2019, to unitholders of record at the close of business on February 19, 2019.