Viper Energy Partners (VNOM) 10-K 7 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Registrant Name	Viper Energy Partners LP
Entity Central Index Key	1,602,065
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Units, Units Outstanding		113,882,045
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 394,183,228

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 24,197	$ 9,213
Restricted cash	0	500
Royalty income receivable	25,754	10,043
Royalty income receivable—related party	5,142	3,470
Other current assets	355	187
Total current assets	55,448	23,413
Property and equipment:
Oil and natural gas interests, full cost method of accounting ($514,724 and $252,232 excluded from depletion at December 31, 2017 and 2016, respectively)	1,103,897	760,818
Accumulated depletion and impairment	(189,466)	(148,948)
Oil and natural gas interests, net	914,431	611,870
Funds held in escrow	6,304	0
Other assets	36,854	35,266
Total assets	1,013,037	670,549
Current liabilities:
Accounts payable	2,960	1,780
Other accrued liabilities	2,669	371
Total current liabilities	5,629	2,151
Long-term debt	93,500	120,500
Total liabilities	99,129	122,651
Commitments and contingencies
Unitholders’ equity:
Common units (113,882,045 units issued and outstanding as of December 31, 2017 and 87,800,356 units issued and outstanding as of December 31, 2016 )	913,908	547,898
Total unitholders’ equity	913,908	547,898
Total liabilities and unitholders’ equity	$ 1,013,037	$ 670,549

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Oil and natural gas interests, based on the full cost method of accounting, amount excluded from depletion	$ 514,724	$ 252,232
Common units issued	113,882,045	87,800,356
Common units outstanding	113,882,045	87,800,356

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Royalty income	$ 160,163	$ 78,837	$ 74,859
Lease bonus	11,870	309	0
Total operating income	172,033	79,146	74,859
Costs and expenses:
Production and ad valorem taxes	10,608	5,544	5,531
Gathering and transportation	789	415	259
Depletion	40,519	29,820	35,436
Impairment	0	47,469	3,423
General and administrative expenses	6,296	5,209	5,835
Total costs and expenses	58,212	88,457	50,484
Income (loss) from operations	113,821	(9,311)	24,375
Other income (expense):
Interest expense, net	(3,164)	(2,455)	(1,110)
Other income, net	821	867	1,154
Total other income (expense), net	(2,343)	(1,588)	44
Net income (loss)	$ 111,478	$ (10,899)	$ 24,419
Net income (loss) attributable to common limited partners per unit:
Basic (dollars per unit)	$ 1.07	$ (0.13)	$ 0.31
Diluted (dollars per unit)	$ 1.07	$ (0.13)	$ 0.31
Weighted average number of limited partner units outstanding:
Basic (in units)	104,318	83,081	79,717
Diluted (in units)	104,383	83,081	79,727

Statement of Consolidated Unith

Statement of Consolidated Unitholders' Equity and Members' Equity - USD ($) $ in Thousands	Total	Limited Partner [Member]	Diamondback Limited Partner [Member]Limited Partner [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
Common Stock, Shares, Outstanding		79,709,000
Partners' capital at Dec. 31, 2014		$ 535,351
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income (loss)	$ 24,419	24,419
Unit-based compensation		$ 3,929
Stock Issued During Period, Shares, Unit-based		17,000
Distribution to public		$ (7,968)
Distribution to Diamondback			$ (60,587)
Partners' capital at Dec. 31, 2015		$ 495,144
Increase (Decrease) in Partners' Capital [Roll Forward]
Common Stock, Shares, Outstanding		79,726,000
Net income (loss)	(10,899)	$ (10,899)
Net proceeds from the issuance of common units		$ 93,462	$ 31,200
Units issued in public offering		6,050,000	2,000,000
Unit-based compensation		$ 3,815
Stock Issued During Period, Shares, Unit-based		24,000
Distribution to public		$ (9,574)
Distribution to Diamondback			$ (55,250)
Partners' capital at Dec. 31, 2016	547,898	$ 547,898
Increase (Decrease) in Partners' Capital [Roll Forward]
Common Stock, Shares, Outstanding		87,800,000
Net income (loss)	$ 111,478	$ 111,478
Net proceeds from the issuance of common units		$ 369,896	$ 10,067
Units issued in public offering		25,175,000	700,000
Partners' Capital Account, Acquisitions		$ 3,050
Partners' Capital Account, Units, Acquisitions		175,000
Unit-based compensation		$ 2,395
Stock Issued During Period, Shares, Unit-based	32,176	32,000
Distribution to public		$ (41,367)
Distribution to Diamondback			$ (89,509)
Partners' capital at Dec. 31, 2017	$ 913,908	$ 913,908
Increase (Decrease) in Partners' Capital [Roll Forward]
Common Stock, Shares, Outstanding		113,882,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ 111,478	$ (10,899)	$ 24,419
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion	40,519	29,820	35,436
Impairment	0	47,469	3,423
Amortization of debt issuance costs	589	401	314
Non-cash unit-based compensation	2,395	3,815	3,929
Changes in operating assets and liabilities:
Restricted cash	500	0	0
Royalty income receivable	(15,711)	(4,144)	(1,130)
Royalty income receivable—related party	(1,672)	0	0
Accounts payable—related party	0	(4)	4
Accounts payable and other accrued liabilities	1,298	1,945	(1,968)
Other current assets	(177)	224	(595)
Net cash provided by operating activities	139,219	68,627	63,832
Cash flows from investing activities:
Acquisition of mineral interests	(344,079)	(205,721)	(43,907)
Net cash used in investing activities	(344,079)	(205,721)	(43,907)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	278,500	164,000	34,500
Repayment on credit facility	(305,500)	(78,000)	0
Debt issuance costs	(2,259)	(442)	(441)
Proceeds from public offerings	380,412	125,580	0
Public offering costs	(433)	(546)	0
Distributions to partners	(130,876)	(64,824)	(68,555)
Net cash provided by (used in) financing activities	219,844	145,768	(34,496)
Net increase (decrease) in cash	14,984	8,674	(14,571)
Cash and cash equivalents at beginning of period	9,213	539	15,110
Cash and cash equivalents at end of period	24,197	9,213	539
Supplemental disclosure of cash flow information:
Interest paid	$ 2,589	$ 1,953	$ 745

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2017
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. Unless the context requires otherwise, references to the “Partnership” are intended to mean the business and operations of Viper Energy Partners LP and its consolidated subsidiary, Viper Energy Partners LLC (the “Predecessor”). As of December 31, 2017 , a wholly-owned subsidiary of Diamondback, Viper Energy Partners GP LLC (the “General Partner”), held a 100% non-economic general partner interest in the Partnership and Diamondback had an approximate 64% limited partner interest in the Partnership. Diamondback owns and controls the General Partner. Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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 and unit–based compensation. 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. Royalty Income Receivable Royalty income receivable consist of receivables from oil and natural gas sales delivered to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Some of the Partnership’s oil and natural gas properties are contractually operated by Diamondback. Most payments are received within three months after the production date. Royalty income receivable are stated at amounts due from operators, net of an allowance for doubtful accounts when the Partnership believes collection is doubtful. Royalty income receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines any allowance by considering a number of factors, including the length of time royalty income receivable are past due, the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to us, the condition of the general economy and the industry as a whole. The Partnership writes off specific royalty income receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. The Partnership determined that an allowance was unnecessary at both December 31, 2017 and 2016 . 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, 2017 and 2016 , the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $10.07 , $12.67 and $17.88 for the years ended December 31, 2017 , 2016 and 2015 , respectively. Depletion for oil and gas properties was $40.5 million , $29.8 million and $35.4 million for the years ended December 31, 2017 , 2016 and 2015 , 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 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 writedown is required. During the years ended December 31, 2016 and 2015 , the Partnership recorded impairments on proved oil and natural gas properties of $47.5 million and $3.4 million , respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 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 $4.4 million , $2.2 million and $1.7 million , net of accumulated amortization of $1.4 million , $0.8 million and $0.4 million as of December 31, 2017 , 2016 and 2015 , 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 title passes to the purchaser. 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, 2017 , two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (US) Company (“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% ). For the year ended December 31, 2015 , two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading ( 68% ) and RSP Permian LLC ( 25% ). 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 partnership operating and financial policies. This interest was acquired during the year ended December 31, 2014 and is accounted for under the cost method. Under the cost method, investments are carried at cost and are adjusted only for other than temporary declines in fair value, certain distributions and additional investments. As of December 31, 2017 , the book value of this investment was $33.9 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 is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s partners are responsible for federal income taxes on their share of the Partnership’s taxable income. The Partnership is subject to the Texas margin tax. Diamondback does not expect any Texas margin tax to be due for the years ended December 31, 2017 , 2016 and 2015 , so no amount has been provided in the accompanying financial statements. New Accounting Pronouncements Recently Issued 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 in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Partnership will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Partnership has reviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, the Partnership will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, the Partnership will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Partnership. The Partnership does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP. 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 will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment. 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 will adopt this update retrospectively effective January 1, 2018. The adoption of this update will only effect 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 will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of the filing date, the Partnership was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. Therefore, the Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity. In 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.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions	ACQUISITIONS 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. 2015 Activity During the year ended December 31, 2015 , the Partnership acquired an approximate average 1.5% overriding royalty interest in certain acreage primarily located in Howard County, Texas from Diamondback for $31.1 million . This acquisition was primarily funded with borrowings under the Partnership’s credit agreement discussed in Note 5 .

Oil and Natural Gas Interests

Oil and Natural Gas Interests	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Oil and Natural Gas Interests	OIL AND NATURAL GAS INTERESTS Oil and natural gas interests include the following: December 31, 2017 2016 (in thousands) Oil and natural gas interests: Subject to depletion $ 589,173 $ 508,586 Not subject to depletion 514,724 252,232 Gross oil and natural gas interests 1,103,897 760,818 Accumulated depletion and impairment (189,466 ) (148,948 ) Oil and natural gas interests, net $ 914,431 $ 611,870 Balance of costs not subject to depletion: Incurred in 2017 $ 284,471 Incurred in 2016 158,156 Incurred in 2015 30,896 Incurred in 2014 41,201 Total not subject to depletion $ 514,724 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 non-cash impairments for the years ended December 31, 2016 and 2015 of $47.5 million and $3.4 million , respectively, which are included in accumulated depletion and impairment. There was no impairment recorded for the year ended December 31, 2017 . For 2016 and 2015, the impairment charges 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

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	DEBT Credit Agreement-Wells Fargo Bank On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on its oil and natural gas reserves and other factors (the “borrowing base”) of $400.0 million , subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12 -month period. As of December 31, 2017 , the borrowing base was set at $400.0 million , and the Partnership had $93.5 million of outstanding borrowings and $306.5 million available for future borrowings under its revolving credit facility. The outstanding borrowings under the credit agreement bear interest at a rate elected by the Partnership that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3 -month LIBOR plus 1.0% ) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternative base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of our and our subsidiary’s assets. The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below. Financial Covenant Required Ratio Ratio of total debt to EBITDAX Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As of December 31, 2017 , the Partnership 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 Partnership’s credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS Acquisition During the year ended December 31, 2015, the Partnership acquired an approximate average 1.5% overriding royalty interest in certain acreage primarily located in Howard County, Texas from Diamondback for $31.1 million . This acquisition was primarily funded with borrowings under the Partnership’s credit agreement discussed in Note 5. Partnership Agreement In connection with the closing of the IPO, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership dated June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For the year ended December 31, 2017 , the General Partner received from the Partnership reimbursements of $2.5 million . For the year ended December 31, 2016 , the General Partner did no t receive any reimbursements from the Partnership. For the year ended December 31, 2015 , the General Partner did not receive any reimbursements from the Partnership other than the $4,000 outstanding at December 31, 2014. 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 had an initial term of two years commencing on June 23, 2014, and continues for additional one -year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Partnership terminates the Advisory Services Agreement, the Partnership is obligated to pay all amounts due through the remaining term. In addition, the Partnership agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of the General Partner, if, and to the extent, the Partnership requests services from Wexford in connection with acquisitions and divestitures, financings or other transactions in which the Partnership may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Partnership’s day-to-day business or operations. The Partnership has agreed to indemnify Wexford and its affiliates from their losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. For the years ended December 31, 2017 and 2016 , the Partnership did no t pay any amounts under the Advisory Services Agreement. For the year ended December 31, 2015 , the Partnership paid $0.5 million under the Advisory Services Agreement. Tax Sharing In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. Lease Bonus During the 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

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2017
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 9,070,356 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, 2017 , 2016 and 2015 , the Partnership incurred $2.4 million , $3.8 million and $3.9 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 became 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. As of December 31, 2017, all vested unit options automatically terminated and became null and void. 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, 2017 : Weighted Average Unit Exercise Remaining Intrinsic (in years) (in thousands) Outstanding at December 31, 2016 2,424,266 $ 26.00 Expired/Forfeited (2,416,666 ) $ 26.00 Outstanding at December 31, 2017 7,600 $ 18.49 0.00 $ — Vested and Expected to Vest at December 31, 2017 7,600 $ 18.49 0.00 $ — 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 following table presents the phantom unit activity under the LTIP for the year ended December 31, 2017 : Phantom Weighted Average Unvested at December 31, 2016 21,048 $ 16.23 Granted 116,567 $ 17.09 Vested (32,176 ) $ 16.49 Unvested at December 31, 2017 105,439 $ 17.10 The aggregate fair value of phantom units that vested during the year ended December 31, 2017 was $0.5 million . As of December 31, 2017 , the unrecognized compensation cost related to unvested phantom units was $1.3 million . Such cost is expected to be recognized over a weighted-average period of 1.4 years.

Partners' Capital and Partnersh

Partners' Capital and Partnership Distributions	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Partners' Capital and Partnership Distributions	PARTNERS’ CAPITAL AND PARTNERSHIP DISTRIBUTIONS The Partnership has general partner and common unit partnership interests. The general partner interest is a non-economic interest and is not entitled to any cash distributions. At December 31, 2017 , the Partnership had a total of 113,882,045 common units issued and outstanding, of which 73,150,000 common units were owned by Diamondback, representing approximately 64% of the total Partnership units outstanding. The following table summarizes changes in the number of the Partnership’s common units: Common Units Balance at December 31, 2016 87,800,356 Common units issued in public offerings 25,875,000 Common units vested and issued under the LTIP 32,176 Common units issued for acquisition 174,513 Balance at December 31, 2017 113,882,045 The board of directors of the General Partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis, beginning with the quarter ending September 30, 2014. Cash distributions are made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for each quarter generally equals Adjusted EBITDA reduced for cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. 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) February 5, 2015 Q4 2014 $ 0.250 February 27, 2015 $ 17,612 May 1, 2015 Q1 2015 $ 0.189 May 22, 2015 $ 13,385 July 31, 2015 Q2 2015 $ 0.220 August 21, 2015 $ 15,499 October 30, 2015 Q3 2015 $ 0.200 November 20, 2015 $ 14,091 February 12, 2016 Q4 2015 $ 0.228 February 26, 2016 $ 16,063 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

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [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, 2017 , 2016 and 2015 , since this is the amount of net income that is attributable to the Partnership’s common units. The Partnership’s net income (loss) is allocated wholly to the common units as the General Partner does not have an economic interest. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 8 —Partners’ Capital 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, 2017 2016 2015 (In thousands, except per unit amounts) Net income (loss) attributable to the period 111,478 (10,899 ) 24,419 Weighted average common units outstanding Basic weighted average common units outstanding 104,318 83,081 79,717 Effect of dilutive securities: Potential common units issuable 65 — 10 Diluted weighted average common units outstanding 104,383 83,081 79,727 Net income (loss) per common unit, basic $1.07 $(0.13) $0.31 Net income (loss) per common unit, diluted $1.07 $(0.13) $0.31 For the years ended December 31, 2017 , 2016 and 2015 , there were 39,788 units, 1,567,155 units and 1,697,142 units, respectively, that were not included in 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
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

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Cash Distribution On January 31, 2018, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2017 of $0.46 per common unit, payable on February 26, 2018 , to unitholders of record at the close of business on February 19, 2018 . Recent Acquisitions Since the end of the fourth quarter of 2017, the Partnership acquired from unrelated third party sellers additional mineral interests underlying 137,443 gross acres, 1,617 net acres and 900 net royalty acres in the Permian Basin and Eagle Ford Shale for an aggregate of approximately $149.4 million , subject to post-closing adjustments. As a result, as of February 2, 2018, the Partnership’s assets included mineral interests underlying 385,046 gross acres, 45,460 net acres and 10,470 net royalty acres primarily in the Permian Basin and Eagle Ford Shale. These acquisitions were primarily funded with cash on hand and borrowings under the Partnership’s revolving credit facility.

Supplemental Information on Oil

Supplemental Information on Oil and Natural Gas Operations (Unaudited)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 (In thousands) Oil and natural gas interests: Proved $ 589,173 $ 508,586 Unproved 514,724 252,232 Total oil and natural gas interests 1,103,897 760,818 Accumulated depletion and impairment (189,466 ) (148,948 ) Net oil and natural gas interests capitalized $ 914,431 $ 611,870 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, 2017 2016 2015 (In thousands) Acquisition costs Proved properties $ 55,948 $ 31,441 $ 4,121 Unproved properties 287,131 174,385 39,786 Total $ 343,079 $ 205,826 $ 43,907 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, 2017 2016 2015 (In thousands) Royalty income $ 160,163 $ 78,837 $ 74,859 Production and ad valorem taxes (10,608 ) (5,544 ) (5,531 ) Gathering and transportation (789 ) (415 ) (259 ) Depletion (40,519 ) (29,820 ) (35,436 ) Impairment — (47,469 ) (3,423 ) Results of operations from oil, natural gas and natural gas liquids $ 108,247 $ (4,411 ) $ 30,210 Oil and Natural Gas Reserves Proved oil and natural gas reserve estimates as of December 31, 2017 , 2016 and 2015 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 Natural Gas Liquids Natural Gas (In thousands) Proved Developed and Undeveloped Reserves: As of December 31, 2014 12,830 2,514 18,994 Purchase of reserves in place 107 3 431 Extensions and discoveries 8,450 2,013 9,476 Revisions of previous estimates (1,454 ) (375 ) (3,465 ) Production (1,555 ) (239 ) (1,128 ) 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 Proved Developed Reserves: December 31, 2015 9,700 2,205 13,739 December 31, 2016 12,332 3,247 15,933 December 31, 2017 18,788 4,536 29,256 Proved Undeveloped Reserves: December 31, 2015 8,677 1,711 10,569 December 31, 2016 9,012 2,329 11,158 December 31, 2017 7,097 1,759 7,139 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, 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 primarily 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. During the year ended December 31, 2015, purchases of reserves were primarily from one acquisition in Howard County and several minor acquisitions in other areas consisting of 124 vertical wells and one horizontal well. Extensions are primarily the result of horizontal development of the Wolfcamp B and Lower Spraberry shales. The extensions were the result of one vertical well and 83 horizontal wells, of which 51 horizontal wells are in the proved undeveloped category. Diamondback is the operator of 57 of the 84 total wells. Revisions are primarily the result of downgrading nine horizontal wells and 48 vertical wells that were classified as PUDs into the probable category as a result of lower product prices and subsequent changes in drilling plans such that the wells are no longer expected to be drilled within five years of when they were originally booked. 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, 2017 , 2016 and 2015 . December 31, 2017 2016 2015 (In thousands) Future cash inflows $ 1,445,883 $ 948,090 $ 912,276 Future production taxes (125,564 ) (69,109 ) (61,777 ) Future state margin tax expenses (6,932 ) (4,615 ) (4,789 ) Future net cash flows 1,313,387 874,366 845,710 10% discount to reflect timing of cash flows (688,039 ) (461,785 ) (449,947 ) Standardized measure of discounted future net cash flows $ 625,348 $ 412,581 $ 395,763 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, 2017 2016 2015 Unweighted Arithmetic Average First-Day-of-the-Month Prices Oil (per Bbl) $ 48.21 $ 39.64 $ 45.03 Natural gas (per Mcf) $ 2.13 $ 1.36 $ 1.64 Natural gas liquids (per Bbl) $ 19.15 $ 11.69 $ 11.41 Principal changes in the standardized measure of discounted future net cash flows attributable to the Partnership’s proved reserves are as follows: December 31, 2017 2016 2015 (In thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 412,581 $ 395,763 $ 553,236 Purchase of minerals in place 54,662 23,651 2,963 Sales of oil and natural gas, net of production costs (149,555 ) (74,628 ) (69,328 ) Extensions and discoveries 214,479 104,451 181,330 Net changes in prices and production costs 99,382 (42,155 ) (269,154 ) Revisions of previous quantity estimates (50,773 ) (42,883 ) (71,399 ) Net changes in state margin taxes (1,129 ) 51 (1,884 ) Accretion of discount 41,477 39,800 54,911 Net changes in timing of production and other 4,224 8,531 15,088 Standardized measure of discounted future net cash flows at the end of the period $ 625,348 $ 412,581 $ 395,763

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information [Text Block]	QUARTERLY FINANCIAL DATA (Unaudited) 2017 First Second Third Fourth (In thousands, except per unit amounts) Royalty income $ 32,050 $ 35,933 $ 42,211 $ 49,969 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 2016 First Second Third Fourth (In thousands, except per unit amounts) Royalty income $ 14,086 $ 16,836 $ 19,992 $ 27,923 Income (loss) from operations (23,104 ) (13,711 ) 10,594 16,910 Net income (loss) (23,335 ) (14,020 ) 10,202 16,254 Net income (loss) attributable to common limited partners per unit: Basic $ (0.29 ) $ (0.18 ) $ 0.12 $ 0.20 Diluted $ (0.29 ) $ (0.18 ) $ 0.12 $ 0.20

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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 and unit–based compensation.
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	Royalty Income Receivable Royalty income receivable consist of receivables from oil and natural gas sales delivered to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Some of the Partnership’s oil and natural gas properties are contractually operated by Diamondback. Most payments are received within three months after the production date. Royalty income receivable are stated at amounts due from operators, net of an allowance for doubtful accounts when the Partnership believes collection is doubtful. Royalty income receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines any allowance by considering a number of factors, including the length of time royalty income receivable are past due, the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to us, the condition of the general economy and the industry as a whole. The Partnership writes off specific royalty income receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts.
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	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. 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 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 writedown is required. 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. 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.
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 title passes to the purchaser. 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	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. 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	Investments The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over partnership operating and financial policies. This interest was acquired during the year ended December 31, 2014 and is accounted for under the cost method. Under the cost method, investments are carried at cost and are adjusted only for other than temporary declines in fair value, certain distributions and additional investments.
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 is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s partners are responsible for federal income taxes on their share of the Partnership’s taxable income. The Partnership is subject to the Texas margin tax.
New Accounting Pronouncements	New Accounting Pronouncements Recently Issued 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 in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Partnership will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Partnership has reviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, the Partnership will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, the Partnership will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Partnership. The Partnership does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP. 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 will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment. 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 will adopt this update retrospectively effective January 1, 2018. The adoption of this update will only effect 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 will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of the filing date, the Partnership was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. Therefore, the Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity. In 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.

Oil and Natural Gas Interests (

Oil and Natural Gas Interests (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Aggregate capitalized costs related to oil and natural gas production activities	Oil and natural gas interests include the following: December 31, 2017 2016 (in thousands) Oil and natural gas interests: Subject to depletion $ 589,173 $ 508,586 Not subject to depletion 514,724 252,232 Gross oil and natural gas interests 1,103,897 760,818 Accumulated depletion and impairment (189,466 ) (148,948 ) Oil and natural gas interests, net $ 914,431 $ 611,870 Balance of costs not subject to depletion: Incurred in 2017 $ 284,471 Incurred in 2016 158,156 Incurred in 2015 30,896 Incurred in 2014 41,201 Total not subject to depletion $ 514,724 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: December 31, 2017 2016 (In thousands) Oil and natural gas interests: Proved $ 589,173 $ 508,586 Unproved 514,724 252,232 Total oil and natural gas interests 1,103,897 760,818 Accumulated depletion and impairment (189,466 ) (148,948 ) Net oil and natural gas interests capitalized $ 914,431 $ 611,870

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of financial covenants	Financial Covenant Required Ratio Ratio of total debt to EBITDAX Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 : Weighted Average Unit Exercise Remaining Intrinsic (in years) (in thousands) Outstanding at December 31, 2016 2,424,266 $ 26.00 Expired/Forfeited (2,416,666 ) $ 26.00 Outstanding at December 31, 2017 7,600 $ 18.49 0.00 $ — Vested and Expected to Vest at December 31, 2017 7,600 $ 18.49 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, 2017 : Phantom Weighted Average Unvested at December 31, 2016 21,048 $ 16.23 Granted 116,567 $ 17.09 Vested (32,176 ) $ 16.49 Unvested at December 31, 2017 105,439 $ 17.10

Partners' Capital and Partner24

Partners' Capital and Partnership Distributions (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2016 87,800,356 Common units issued in public offerings 25,875,000 Common units vested and issued under the LTIP 32,176 Common units issued for acquisition 174,513 Balance at December 31, 2017 113,882,045
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) February 5, 2015 Q4 2014 $ 0.250 February 27, 2015 $ 17,612 May 1, 2015 Q1 2015 $ 0.189 May 22, 2015 $ 13,385 July 31, 2015 Q2 2015 $ 0.220 August 21, 2015 $ 15,499 October 30, 2015 Q3 2015 $ 0.200 November 20, 2015 $ 14,091 February 12, 2016 Q4 2015 $ 0.228 February 26, 2016 $ 16,063 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

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of basic and diluted net income per common unit	Year Ended December 31, 2017 2016 2015 (In thousands, except per unit amounts) Net income (loss) attributable to the period 111,478 (10,899 ) 24,419 Weighted average common units outstanding Basic weighted average common units outstanding 104,318 83,081 79,717 Effect of dilutive securities: Potential common units issuable 65 — 10 Diluted weighted average common units outstanding 104,383 83,081 79,727 Net income (loss) per common unit, basic $1.07 $(0.13) $0.31 Net income (loss) per common unit, diluted $1.07 $(0.13) $0.31

Supplemental Information on O26

Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Aggregate capitalized costs related to oil and natural gas production activities	Oil and natural gas interests include the following: December 31, 2017 2016 (in thousands) Oil and natural gas interests: Subject to depletion $ 589,173 $ 508,586 Not subject to depletion 514,724 252,232 Gross oil and natural gas interests 1,103,897 760,818 Accumulated depletion and impairment (189,466 ) (148,948 ) Oil and natural gas interests, net $ 914,431 $ 611,870 Balance of costs not subject to depletion: Incurred in 2017 $ 284,471 Incurred in 2016 158,156 Incurred in 2015 30,896 Incurred in 2014 41,201 Total not subject to depletion $ 514,724 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: December 31, 2017 2016 (In thousands) Oil and natural gas interests: Proved $ 589,173 $ 508,586 Unproved 514,724 252,232 Total oil and natural gas interests 1,103,897 760,818 Accumulated depletion and impairment (189,466 ) (148,948 ) Net oil and natural gas interests capitalized $ 914,431 $ 611,870
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, 2017 2016 2015 (In thousands) Acquisition costs Proved properties $ 55,948 $ 31,441 $ 4,121 Unproved properties 287,131 174,385 39,786 Total $ 343,079 $ 205,826 $ 43,907
Results of Operations for Oil and 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, 2017 2016 2015 (In thousands) Royalty income $ 160,163 $ 78,837 $ 74,859 Production and ad valorem taxes (10,608 ) (5,544 ) (5,531 ) Gathering and transportation (789 ) (415 ) (259 ) Depletion (40,519 ) (29,820 ) (35,436 ) Impairment — (47,469 ) (3,423 ) Results of operations from oil, natural gas and natural gas liquids $ 108,247 $ (4,411 ) $ 30,210
Changes in Estimated Proved Reserves	The changes in estimated proved reserves are as follows: Oil Natural Gas Liquids Natural Gas (In thousands) Proved Developed and Undeveloped Reserves: As of December 31, 2014 12,830 2,514 18,994 Purchase of reserves in place 107 3 431 Extensions and discoveries 8,450 2,013 9,476 Revisions of previous estimates (1,454 ) (375 ) (3,465 ) Production (1,555 ) (239 ) (1,128 ) 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 Proved Developed Reserves: December 31, 2015 9,700 2,205 13,739 December 31, 2016 12,332 3,247 15,933 December 31, 2017 18,788 4,536 29,256 Proved Undeveloped Reserves: December 31, 2015 8,677 1,711 10,569 December 31, 2016 9,012 2,329 11,158 December 31, 2017 7,097 1,759 7,139
Standardized Measure of Discounted Future Net Cash Flows	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, 2017 , 2016 and 2015 . December 31, 2017 2016 2015 (In thousands) Future cash inflows $ 1,445,883 $ 948,090 $ 912,276 Future production taxes (125,564 ) (69,109 ) (61,777 ) Future state margin tax expenses (6,932 ) (4,615 ) (4,789 ) Future net cash flows 1,313,387 874,366 845,710 10% discount to reflect timing of cash flows (688,039 ) (461,785 ) (449,947 ) Standardized measure of discounted future net cash flows $ 625,348 $ 412,581 $ 395,763
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, 2017 2016 2015 Unweighted Arithmetic Average First-Day-of-the-Month Prices Oil (per Bbl) $ 48.21 $ 39.64 $ 45.03 Natural gas (per Mcf) $ 2.13 $ 1.36 $ 1.64 Natural gas liquids (per Bbl) $ 19.15 $ 11.69 $ 11.41
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, 2017 2016 2015 (In thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 412,581 $ 395,763 $ 553,236 Purchase of minerals in place 54,662 23,651 2,963 Sales of oil and natural gas, net of production costs (149,555 ) (74,628 ) (69,328 ) Extensions and discoveries 214,479 104,451 181,330 Net changes in prices and production costs 99,382 (42,155 ) (269,154 ) Revisions of previous quantity estimates (50,773 ) (42,883 ) (71,399 ) Net changes in state margin taxes (1,129 ) 51 (1,884 ) Accretion of discount 41,477 39,800 54,911 Net changes in timing of production and other 4,224 8,531 15,088 Standardized measure of discounted future net cash flows at the end of the period $ 625,348 $ 412,581 $ 395,763

Quarterly Financial Data (Una27

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule of Quarterly Financial Information [Table Text Block]	2017 First Second Third Fourth (In thousands, except per unit amounts) Royalty income $ 32,050 $ 35,933 $ 42,211 $ 49,969 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 2016 First Second Third Fourth (In thousands, except per unit amounts) Royalty income $ 14,086 $ 16,836 $ 19,992 $ 27,923 Income (loss) from operations (23,104 ) (13,711 ) 10,594 16,910 Net income (loss) (23,335 ) (14,020 ) 10,202 16,254 Net income (loss) attributable to common limited partners per unit: Basic $ (0.29 ) $ (0.18 ) $ 0.12 $ 0.20 Diluted $ (0.29 ) $ (0.18 ) $ 0.12 $ 0.20

Organization and Basis of Pre28

Organization and Basis of Presentation (Details)	12 Months Ended
	Dec. 31, 2017
General Partner [Member]
Limited Partners' Capital Account [Line Items]
Percent of General Partner interest	100.00%
Diamondback Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Percent of limited partnership interest	64.00%

Summary of Significant Accoun29

Summary of Significant Accounting Policies - Oil and Natural Gas Properties, Capitalized Interest, and Debt Issuance Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / Boe	Dec. 31, 2016USD ($)$ / Boe	Dec. 31, 2015USD ($)$ / Boe
Accounting Policies [Abstract]
Average depletion rate per barrel equivalent unit of production | $ / Boe	10.07	12.67	17.88
Depletion of oil and gas properties	$ 40,519	$ 29,820	$ 35,436
Impairment of oil and gas properties	0	47,469	3,423
Debt issuance costs, net of accumulated amortizations	4,419	2,159	1,717
Debit issuance costs, accumulated amortization	$ 1,415	$ 826	$ 425

Summary of Significant Accoun30

Summary of Significant Accounting Policies - Concentrations and Investments (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 31, 2018	Dec. 31, 2014
Concentration Risk [Line Items]
Impairment	$ 0	$ 47,469	$ 3,423
Restricted cash	$ 0	$ 500			$ 500
Shell Trading [Member] | Customer Concentration Risk [Member] | Royalty Interest Revenue [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	47.00%	57.00%	68.00%
RSP Permian LLC [Member] | Customer Concentration Risk [Member] | Royalty Interest Revenue [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	23.00%	32.00%	25.00%
Other assets [Member]
Concentration Risk [Line Items]
Value of cost method investment	$ 33,851
Subsequent Event [Member]
Concentration Risk [Line Items]
Value of cost method investment				$ 15,200
Cost Method Investment, Value per Unit				$ 15.20

Acquisitions (Details)

Acquisitions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)ashares	Dec. 31, 2016USD ($)a	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Payments to acquire mineral interests	$ 344,079	$ 205,721	$ 43,907
Series of Individually Immaterial Business Acquisitions [Member]
Business Acquisition [Line Items]
Mineral Properties Acquired, Net Royalty Acres | a	3,157	2,142
Mineral Properties, Net Royalty Acres | a	9,570
Payments to acquire mineral interests	$ 343,100	$ 205,700
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	174,513
Howard County, Texas [Member] | Diamondback E&P LLC [Member]
Business Acquisition [Line Items]
Payments to acquire mineral interests			$ 31,100
Oil and Gas Property, Percent of Royalty Interest			1.50%

Oil and Natural Gas Interests32

Oil and Natural Gas Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Subject to depletion	$ 589,173	$ 508,586
Not subject to depletion	514,724	252,232
Gross oil and natural gas interests	1,103,897	760,818
Accumulated depletion and impairment	(189,466)	(148,948)
Oil and natural gas interests, net	914,431	611,870
Balance of costs not subject to depletion:	284,471	158,156	$ 30,896	$ 41,201
Impairment	$ 0	$ 47,469	$ 3,423
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

Debt - Credit Facility (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)redetermindation
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000
Number of additional redeterminations that may be requested | redetermindation	3
Period of redeterminations	12 months
Current borrowing capacity	$ 400
Amount outstanding under credit facility	93.5
Remaining borrowing capacity	$ 306.5
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 (Det

Debt - Financial Covenants (Details) $ in Millions	Dec. 31, 2017USD ($)
Line of Credit Facility [Line Items]
Maximum issuance of unsecured debt	$ 400
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
Minimum [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, not less than 1.0	1

Related Party Transactions (Det

Related Party Transactions (Details)	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Related Party Transaction [Line Items]
Payments to acquire mineral interests	$ 344,079,000	$ 205,721,000	$ 43,907,000
General Partner [Member] | Partnership Agreement [Member]
Related Party Transaction [Line Items]
Incurred costs for transactions with related party	2,500,000	0
Accounts Payable, Related Parties, Current				$ 4,000
Affiliated Entity [Member] | Advisory Services Agreement [Member]
Related Party Transaction [Line Items]
Incurred costs for transactions with related party	0	0	$ 500,000
Advisory services agreement, annual fee	$ 500,000
Term of advisory services agreement	2 years
Renewal term of advisory services agreement	1 year
Minimum period for cancellation of additional one-year periods	10 days
Agreement termination, written notice period	30 days
Diamondback Limited Partner [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 100,000	$ 300,000
Number of leases extended	2	6
Average price per acre	$ 7,459	$ 1,371
Howard County, Texas [Member] | Diamondback E&P LLC [Member]
Related Party Transaction [Line Items]
Oil and Gas Property, Percent of Royalty Interest			1.50%
Payments to acquire mineral interests			$ 31,100,000

Unit-Based Compensation Additio

Unit-Based Compensation Additional Disclosures (Details) - USD ($) $ in Millions	Jun. 17, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units reserved for issuance		9,070,356
Equity-based compensation		$ 2.4	$ 3.8	$ 3.9
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 Valuati

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 Op

Unit-Based Compensation Unit Option Activity (Details) - Unit Options [Member] $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Number of Options
Outstanding at December 31, 2016 | shares	2,424,266
Expired/Forfeited | shares	(2,416,666)
Outstanding at December 31, 2017 | shares	7,600
Vested and Expected to Vest at December 31, 2017 | shares	7,600
Weighted Average Exercise Price
Outstanding at December 31, 2016 | $ / shares	$ 26
Expired/Forfeited | $ / shares	26
Outstanding at December 31, 2017 | $ / shares	18.49
Vested and Expected to Vest at December 31, 2017 | $ / shares	$ 18.49
Outstanding at end of period, remaining term	0 years
Vested and expected to vest at end of period, remaining term	0 years
Outstanding at end of period, intrinsic value | $	$ 0
Vested and expected to vest at end of period, intrinsic value | $	$ 0

Unit-Based Compensation Phantom

Unit-Based Compensation Phantom Units (Details) - Phantom Share Units (PSUs) [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Unvested at December 31, 2016 | shares	21,048
Granted | shares	116,567
Vested | shares	(32,176)
Unvested at December 31, 2017 | shares	105,439
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested at December 31, 2016 | $ / shares	$ 16.23
Granted | $ / shares	17.09
Vested | $ / shares	16.49
Unvested at December 31, 2017 | $ / shares	$ 17.10
Equity Instruments Other than Options, Vested in Period, Fair Value | $	$ 0.5
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized | $	$ 1.3
Unrecognized compensation cost related to unvested unit options, period of recognition	1 year 4 months 17 days

Partners' Capital and Partner40

Partners' Capital and Partnership Distributions (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Limited Partners' Capital Account [Line Items]
Common units issued	113,882,045	87,800,356
Common units outstanding	113,882,045	87,800,356
Partners' Capital Account, Units, Unit-based Compensation	32,176
Diamondback Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Units of partnership interest	73,150,000
Percent of limited partnership interest	64.00%
Follow-on Public Offering [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering	25,875,000
Private Placement [Member]
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Acquisitions	174,513

Partnership Distributions (Deta

Partnership Distributions (Details) - Cash Distribution [Member] - USD ($) $ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Dec. 31, 2017

Distribution Made to Limited Partner [Line Items]

Distribution Made to Limited Partner, Declaration Date

Oct. 16, 2017

Jul. 28, 2017

Apr. 28, 2017

Feb. 3, 2017

Oct. 25, 2016

Jul. 21, 2016

May 2, 2016

Feb. 12, 2016

Oct. 30, 2015

Jul. 31, 2015

May 1, 2015

Feb. 5, 2015

Cash distributions, distribution period after quarter end

60 days

Distribution Made to Limited Partner, Distribution Date

Nov. 14, 2017

Aug. 24, 2017

May 25, 2017

Feb. 24, 2017

Nov. 18, 2016

Aug. 22, 2016

May 23, 2016

Feb. 26, 2016

Nov. 20, 2015

Aug. 21, 2015

May 22, 2015

Feb. 27, 2015

Diamondback Limited Partner [Member]

Distribution Made to Limited Partner [Line Items]

Distribution Made to Limited Partner, Distributions Declared, Per Unit

$ 0.337

$ 0.332

$ 0.302

$ 0.258

$ 0.207

$ 0.189

$ 0.149

$ 0.228

$ 0.200

$ 0.220

$ 0.189

$ 0.250

Limited Partners' Capital Account, Distribution Amount

$ 24,652

$ 24,286

$ 21,880

$ 18,692

$ 14,997

$ 13,693

$ 10,497

$ 16,063

$ 14,091

$ 15,499

$ 13,385

$ 17,612

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	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, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) attributable to the period	$ 42,070	$ 26,607	$ 22,149	$ 20,652	$ 16,254	$ 10,202	$ (14,020)	$ (23,335)	$ 111,478	$ (10,899)	$ 24,419
Weighted-average common units outstanding, basic									104,318,000	83,081,000	79,717,000
Weighted Average Number Diluted Limited Partnership Units Outstanding Adjustment									65,000	0	10,000
Weighted-average common units outstanding, diluted									104,383,000	83,081,000	79,727,000
Net income per common unit, basic	$ 0.37	$ 0.24	$ 0.23	$ 0.22	$ 0.20	$ 0.12	$ (0.18)	$ (0.29)	$ 1.07	$ (0.13)	$ 0.31
Net income per common unit, diluted	$ 0.37	$ 0.24	$ 0.23	$ 0.22	$ 0.20	$ 0.12	$ (0.18)	$ (0.29)	$ 1.07	$ (0.13)	$ 0.31
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount									39,788	1,567,155	1,697,142

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Thousands

1 Months Ended

3 Months Ended

4 Months Ended

12 Months Ended

Jan. 31, 2018$ / shares

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Feb. 02, 2018USD ($)a

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Subsequent Event [Line Items]

Acquisition of mineral interests | $

$ (344,079)

$ (205,721)

$ (43,907)

Subsequent Event [Member]

Subsequent Event [Line Items]

Mineral Properties, Gross Acres

385,046

Mineral Properties Acquired, Gross Acres

137,443

Mineral Properties Acquired, Net Acres

1,617

Mineral Properties, Net

45,460

Mineral Properties Acquired, Net Royalty Acres

900

Acquisition of mineral interests | $

$ (149,400)

Mineral Properties, Net Royalty Acres

10,470

Cash Distribution [Member]

Subsequent Event [Line Items]

Distribution Made to Limited Partner, Distribution Date

Nov. 14, 2017

Aug. 24, 2017

May 25, 2017

Feb. 24, 2017

Nov. 18, 2016

Aug. 22, 2016

May 23, 2016

Feb. 26, 2016

Nov. 20, 2015

Aug. 21, 2015

May 22, 2015

Feb. 27, 2015

Cash Distribution [Member] | Subsequent Event [Member]

Subsequent Event [Line Items]

Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ / shares

$ 0.460

Distribution Made to Limited Partner, Distribution Date

Feb. 26, 2018

Distribution Made to Limited Partner, Date of Record

Feb. 19, 2018

Supplemental Information on O44

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, 2017	Dec. 31, 2016
Oil and natural gas interests:
Proved properties	$ 589,173	$ 508,586
Unproved properties	514,724	252,232
Total oil and natural gas interests	1,103,897	760,818
Accumulated depletion and impairment	(189,466)	(148,948)
Net oil and natural gas interests capitalized	$ 914,431	$ 611,870

Supplemental Information on O45

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved properties	$ 55,948	$ 31,441	$ 4,121
Unproved properties	287,131	174,385	39,786
Total	$ 343,079	$ 205,826	$ 43,907

Supplemental Information on O46

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Royalty income	$ 49,969	$ 42,211	$ 35,933	$ 32,050	$ 27,923	$ 19,992	$ 16,836	$ 14,086	$ 160,163	$ 78,837	$ 74,859
Production and ad valorem taxes									(10,608)	(5,544)	(5,531)
Gathering and transportation									(789)	(415)	(259)
Depletion									(40,519)	(29,820)	(35,436)
Impairment									0	(47,469)	(3,423)
Results of operations from oil, natural gas and natural gas liquids									$ 108,247	$ (4,411)	$ 30,210

Supplemental Information on O47

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, 2017Mcfbbl	Dec. 31, 2016Mcfbbl	Dec. 31, 2015wellacquisitionMcfbbl
Reserve Quantities [Line Items]
Purchase of reserves in place	3,232	1,575
Extensions and discoveries	11,524	7,125
Revisions of previous estimates	(3,921)	(1,968)
Development Wells Drilled, Net Productive	96	33
Proved Undeveloped Reserves Number of Wells Added	40	32
Number of Developed Wells, Working Interest | well			84
Oil and Gas Acquisition, Number of Existing Vertical Wells | well			124
Number of Oil and Gas Acquisitions | acquisition			1
Oil and Gas Acquisition, Number of Existing Horizontal Wells | well			1
Number of Vertical Wells Developed, Working Interest | well			1
Number of Horizontal Wells Developed, Working Interest | well			83
Proved Undeveloped Reserves, Number of Wells Downgraded | well			51
Proved Undeveloped Reserves, Horizontal Wells Downgraded, Working Interest | well			9
Proved Undeveloped Reserves, Vertical Wells Downgraded, Working Interest | well			48
Proved Undeveloped Reserves, Planned Development Period			5 years
Oil [Member]
Reserve Quantities [Line Items]
Beginning of the period	21,344	18,378	12,830
Purchase of reserves in place	2,106	1,138	107
Extensions and discoveries	7,859	5,647	8,450
Revisions of previous estimates	(2,525)	(2,041)	(1,454)
Production	(2,899)	(1,778)	(1,555)
End of period	25,885	21,344	18,378
Proved Developed Reserves (Volume)	18,788	12,332	9,700
Proved Undeveloped Reserve (Volume)	7,097	9,012	8,677
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning of the period	5,576	3,916	2,514
Purchase of reserves in place	252	437	3
Extensions and discoveries	1,813	1,477	2,013
Revisions of previous estimates	(813)	74	(375)
Production	(533)	(328)	(239)
End of period	6,295	5,576	3,916
Proved Developed Reserves (Volume)	4,536	3,247	2,205
Proved Undeveloped Reserve (Volume)	1,759	2,329	1,711
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of the period | Mcf	27,091	24,308	18,994
Purchase of reserves in place | Mcf	5,245	2,315	431
Extensions and discoveries | Mcf	11,106	7,181	9,476
Revisions of previous estimates | Mcf	(3,498)	(5,223)	(3,465)
Production | Mcf	(3,549)	(1,490)	(1,128)
End of period | Mcf	36,395	27,091	24,308
Proved Developed Reserves (Volume) | Mcf	29,256	15,933	13,739
Proved Undeveloped Reserve (Volume) | Mcf	7,139	11,158	10,569
Diamondback Energy, Inc. [Member]
Reserve Quantities [Line Items]
Number of Wells Operated by Others | well			57

Supplemental Information on O48

Supplemental Information on Oil and Natural Gas Operations (Unaudited) Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Future cash inflows	$ 1,445,883	$ 948,090	$ 912,276
Future production taxes	(125,564)	(69,109)	(61,777)
Future state margin tax expense	(6,932)	(4,615)	(4,789)
Future net cash flows	1,313,387	874,366	845,710
10% discount to reflect timing of cash flows	(688,039)	(461,785)	(449,947)
Standardized measure of discounted future net cash flows	$ 625,348	$ 412,581	$ 395,763	$ 553,236

Supplemental Information on O49

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, 2017$ / Mcf$ / bbl	Dec. 31, 2016$ / Mcf$ / bbl	Dec. 31, 2015$ / 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	48.21	39.64	45.03
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	2.13	1.36	1.64
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	19.15	11.69	11.41

Supplemental Information on O50

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at the beginning of the period	$ 412,581	$ 395,763	$ 553,236
Purchase of minerals in place	54,662	23,651	2,963
Sales of oil and natural gas, net of production costs	(149,555)	(74,628)	(69,328)
Extensions and discoveries	214,479	104,451	181,330
Net changes in prices and production costs	99,382	(42,155)	(269,154)
Revisions of previous quantity estimates	(50,773)	(42,883)	(71,399)
Net changes in state margin taxes	(1,129)	51	(1,884)
Accretion of discount	41,477	39,800	54,911
Net changes in timing of production and other	4,224	8,531	15,088
Standardized measure of discounted future net cash flows at the end of the period	$ 625,348	$ 412,581	$ 395,763

Quarterly Financial Data (Una51

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	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, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Royalty income	$ 49,969	$ 42,211	$ 35,933	$ 32,050	$ 27,923	$ 19,992	$ 16,836	$ 14,086	$ 160,163	$ 78,837	$ 74,859
Income from operations	42,825	27,067	22,479	21,450	16,910	10,594	(13,711)	(23,104)	113,821	(9,311)	24,375
Net income (loss)	$ 42,070	$ 26,607	$ 22,149	$ 20,652	$ 16,254	$ 10,202	$ (14,020)	$ (23,335)	$ 111,478	$ (10,899)	$ 24,419
Net income per common unit, basic	$ 0.37	$ 0.24	$ 0.23	$ 0.22	$ 0.20	$ 0.12	$ (0.18)	$ (0.29)	$ 1.07	$ (0.13)	$ 0.31
Net income per common unit, diluted	$ 0.37	$ 0.24	$ 0.23	$ 0.22	$ 0.20	$ 0.12	$ (0.18)	$ (0.29)	$ 1.07	$ (0.13)	$ 0.31