Net income attributable to common limited partners per unit:

$ (10,899)

$ 24,419

$ 29,634

Basic (dollars per unit)

$ (0.13)

$ 0.31

$ 0.29

^[1]

Diluted (dollars per unit)

$ (0.13)

$ 0.31

$ 0.29

^[1]

Weighted average number of limited partner units outstanding:

Basic (in units)

83,081

79,717

78,090

^[1]

Diluted (in units)

83,081

79,727

78,102

^[1]

[1]	2014 information presented is attributable to the period June 23, 2014 through December 31, 2014.

Statement of Consolidated Unitholders' Equity and Members' Equity - USD ($)
shares in Thousands, $ in Thousands

Total

Limited Partner [Member]

Members' Equity [Member]

Diamondback Limited Partner [Member]

Limited Partner [Member]

Diamondback Limited Partner [Member]

Members' Equity [Member]

Partners' capital (Predecessor [Member]) at Dec. 31, 2013

^[1]

$ 2,988

Partners' capital at Dec. 31, 2013

^[1]

$ 2,988

$ 0

Increase (Decrease) in Partners' Capital [Roll Forward]

Contribution of note payable to equity | Predecessor [Member]

29,634

437,115

Contribution of note payable to equity

437,115

Exchange of Predecessor interests for units | Predecessor [Member]

(447,124)

Exchange of Predecessor interests for units

$ 447,124

Stock Issued During Period, Shares, Other

70,450

Stock Issued During Period, Shares, New Issues

9,250

Net proceeds from the issuance of common units | Predecessor [Member]

Net proceeds from the issuance of common units

232,198

$ 232,198

Distribution of net proceeds to Diamondback | Predecessor [Member]

$ 0

Distribution of net proceeds to Diamondback

$ (148,760)

Unit-based compensation | Predecessor [Member]

Unit-based compensation

2,102

$ 2,102

Stock Issued During Period, Shares, Unit-based

Limited Partners' Capital Account, Distribution Amount | Predecessor [Member]

Limited Partners' Capital Account, Distribution Amount

(2,314)

$ (2,314)

Distribution to Diamondback | Predecessor [Member]

Distribution to Diamondback

(17,612)

Partners' capital (Predecessor [Member]) at Dec. 31, 2014

Partners' capital at Dec. 31, 2014

535,351

$ 535,351

Increase (Decrease) in Partners' Capital [Roll Forward]

Common Stock, Shares, Outstanding

79,709

Net income (loss) | Predecessor [Member]

Unit-based compensation | Predecessor [Member]

24,419

$ 24,419

Unit-based compensation

3,929

$ 3,929

Stock Issued During Period, Shares, Unit-based

Limited Partners' Capital Account, Distribution Amount | Predecessor [Member]

Limited Partners' Capital Account, Distribution Amount

(7,968)

$ (7,968)

Distribution to Diamondback | Predecessor [Member]

Distribution to Diamondback

(60,587)

Partners' capital (Predecessor [Member]) at Dec. 31, 2015

Partners' capital at Dec. 31, 2015

495,144

$ 495,144

Increase (Decrease) in Partners' Capital [Roll Forward]

Common Stock, Shares, Outstanding

79,726

Net income (loss) | Predecessor [Member]

Net proceeds from the issuance of common units | Predecessor [Member]

(10,899)

$ (10,899)

Net proceeds from the issuance of common units

93,462

$ 93,462

31,200

$ 31,200

Units issued in public offering

6,050

2,000

Unit-based compensation | Predecessor [Member]

Unit-based compensation

3,815

$ 3,815

Stock Issued During Period, Shares, Unit-based

Limited Partners' Capital Account, Distribution Amount | Predecessor [Member]

Limited Partners' Capital Account, Distribution Amount

(9,574)

$ (9,574)

Distribution to Diamondback | Predecessor [Member]

$ 0

Distribution to Diamondback

$ (55,250)

Partners' capital (Predecessor [Member]) at Dec. 31, 2016

$ 0

Partners' capital at Dec. 31, 2016

$ 547,898

Increase (Decrease) in Partners' Capital [Roll Forward]

Common Stock, Shares, Outstanding

87,800

[1]	See Note 1 for information regarding the basis of financial statement presentation.

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (10,899)	$ 24,419	$ 29,634
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion	29,820	35,436	27,601
Impairment	47,469	3,423	0
Amortization of debt issuance costs	401	314	112
Non-cash unit-based compensation	3,815	3,929	2,102
Changes in operating assets and liabilities:
Restricted cash	0	0	(500)
Royalty income receivable	(4,144)	(1,130)	1,187
Accounts payable—related party	(4)	4	(9,779)
Accounts payable and other accrued liabilities	1,945	(1,968)	1,709
Prepaid expenses and other current assets	224	(595)	(253)
Net cash provided by operating activities	68,627	63,832	51,813
Cash flows from investing activities:
Additions to oil and natural gas interests	0	0	(5,276)
Acquisition of royalty interests	(205,721)	(43,907)	(57,689)
Cost method investment	0	0	(33,850)
Net cash used in investing activities	(205,721)	(43,907)	(96,815)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	164,000	34,500	78,000
Repayment on credit facility	(78,000)	0	(78,000)
Principal payment on subordinated note	0	0	(2,885)
Debt issuance costs	(442)	(441)	(1,277)
Proceeds from public offerings	125,580	0	234,546
Public offering costs	(546)	0	(2,348)
Distribution of net proceeds from public offerings to Diamondback	0	0	(148,760)
Distributions to partners	(64,824)	(68,555)	(19,926)
Net cash provided by (used in) financing activities	145,768	(34,496)	59,350
Net increase (decrease) in cash	8,674	(14,571)	14,348
Cash and cash equivalents at beginning of period	539	15,110	762
Cash and cash equivalents at end of period	9,213	539	15,110
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	1,953	745	16,983
Supplemental disclosure of non—cash transactions:
Note payable converted to equity	0	0	437,115
Capitalized interest	$ 0	$ 0	$ 5,275

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2016
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”). Prior to the completion of the Partnership’s initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests (which included 750,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters), Diamondback owned all of the general and limited partner interests in the Partnership. On June 23, 2014, the Partnership completed its IPO at a price to the public of $26.00 per common unit. The Partnership received proceeds of approximately $137.2 million from the sale of these common units, net of offering expenses and underwriting discounts and commissions. In connection with the IPO, Diamondback contributed all of the membership interests in the Predecessor to the Partnership in exchange for 70,450,000 common units and Diamondback maintained its non-economic general partner interest in the Partnership through its wholly-owned subsidiary, Viper Energy Partners GP LLC (the “General Partner”). In addition, in connection with the closing of the IPO, the Partnership agreed to distribute to Diamondback all cash and cash equivalents and the royalty income receivable on hand in the aggregate amount of $11.3 million and the net proceeds from the IPO. As of December 31, 2014, the Partnership had distributed $148.8 million to Diamondback as part of the IPO transactions. The contribution of the Predecessor to the Partnership was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. The common units were sold to the public at $28.50 per unit and the Partnership received proceeds of approximately $94.8 million from the sale of these common units, net of offering expenses and underwriting discounts and commissions. As of December 31, 2016, the General Partner held a 100% non-economic general partner interest in the Partnership and Diamondback had an approximate 83% limited partner interest in the Partnership. Following the Partnership’s January 2017 underwritten public offering of common units, Diamondback owned approximately 74% of the Partnership’s outstanding common units. Diamondback owns and controls the General Partner. Basis of Presentation The consolidated results of operations following the completion of the IPO are presented together with the results of operations pertaining to the Predecessor. The assets of the Predecessor consisted of mineral interests in oil and natural gas properties in the Permian Basin, which were acquired on September 19, 2013. The contribution of the Predecessor to the Partnership on June 17, 2014 was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. The Partnership did not own any assets prior to June 17, 2014, the date of the contribution agreement by and among Diamondback, the Predecessor, the General Partner and the Partnership. Prior to the IPO, the Predecessor was a wholly owned subsidiary of Diamondback. For periods prior to June 17, 2014, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in members’ equity of the Predecessor and, for periods on and after June 17, 2014, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in partners’ equity of the Partnership and its wholly owned subsidiary. The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“GAAP”). All material intercompany balances and transactions are eliminated in consolidation.

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2016
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 The Predecessor entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The agreement provided that the Predecessor would have the right to terminate the agreement and receive a return of the deposit if the Predecessor in good faith asserted title defects in excess of a certain amount. The Predecessor asserted title defects in excess of the amount and requested that the escrow agent return the deposit. The seller provided the escrow agent with notice alleging the Predecessor did not timely assert title defects in good faith. The escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. 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, 2016 and 2015. 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, 2016 and 2015, 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 $12.67, $17.88 and $24.89 for the years ended December 31, 2016, 2015 and 2014, respectively. Depletion for oil and gas properties was $29.8 million, $35.4 million and $27.6 million for the years ended December 31, 2016, 2015 and 2014, 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, 2014. 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. Capitalized Interest The Partnership capitalizes interest on expenditures made in connection with acquisitions of unproved properties that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these properties to their intended use. Capitalized interest cannot exceed gross interest expense. During the year ended December 31, 2014, the Partnership capitalized approximately $5.3 million of interest expense. The Partnership did not have any capitalized interest for the years ended December 31, 2016 and 2015. Debt Issuance Costs Other assets include capitalized costs of $2.2 million, $1.7 million and $1.3 million, net of accumulated amortization of $0.8 million, $0.4 million and $0.1 million as of December 31, 2016, 2015 and 2014, 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, 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%). For the year ended December 31, 2014, two purchasers each accounted for more than 10% of royalty interest revenue: Shell Trading (70%) and Permian Transport & Trading (15%). 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, 2016, 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. Any amounts related to operations for the period in 2014 prior to the closing of the IPO on June 23, 2014 will be included in Diamondback’s unitary filing for this tax. Diamondback does not expect any Texas margin tax to be due for the years ended December 31, 2016, 2015 and 2014, so no amount has been provided in the accompanying financial statements. New Accounting 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 certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, early application permitted for annual reporting period beginning after December 31, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Partnership is currently evaluating the impact of this standard; however, it does not believe this standard will have a material impact on the Partnership’s financial statements. In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, “Interest–Imputation of Interest”. This update requires that debt issuance costs related to a recognized debt liability (except costs associated with revolving debt arrangements) be presented in the balance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount, to simplify the presentation of debt issuance costs. This update is effective for financial statements issued for fiscal years beginning after December 15, 2015. The Partnership retrospectively adopted this new standard effective January 1, 2016. Adoption of this update did not have a material impact on the Partnership’s consolidated financial statements. 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. This update will be effective for public entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. Entities should apply the amendments by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The Partnership will be required to mark its cost method investment to fair value with the adoption of this update. 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. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Partnership is still evaluating the impact of this standard. In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-08, “Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Partnership is currently evaluating the impact, if any, that the adoption of this update will have on the Partnership’s financial position, results of operations and liquidity. In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-09, "Compensation - Stock Compensation". This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Partnership is currently evaluating the impact that the adoption of this update will have on the Partnership's financial position, results of operations and liquidity. In April 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-10, “Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing”. This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity. In May 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-12, “Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients”. This update applies only to the following areas from Accounting Standards Codification Topic 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity. In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affect 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 a material impact on the Partnership’s financial statements since the Partnership does not have a history of credit losses.

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions	ACQUISITIONS 2016 Activity During 2016, the Partnership acquired mineral interests underlying 61,679 gross (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. 2014 Activity During the year ended December 31, 2014, the Partnership acquired (i) mineral interests underlying an aggregate of approximately 10,364 gross (3,261 net) acres in the Midland and Delaware basins for approximately $57.7 million and (ii) a minor equity interest in an entity that owns mineral, overriding royalty, net profits, leasehold and other similar interests for approximately $33.9 million. The equity interest is so minor that the Partnership has no influence over partnership operating and financial policies and is accounted for under the cost method.

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4845-128472

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1524-128463

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7000-128479

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4922-128472

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-Publisher FASB
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-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4934-128472

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4926-128472

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=73530397&loc=SL65897772-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Oil and Natural Gas Interests

12 Months Ended

Dec. 31, 2016

Oil and Natural Gas Interests

OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:



	December 31,
	2016			2015
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	508,586		$	469,663
Not subject to depletion	252,232			85,329
Gross oil and natural gas interests	760,818			554,992
Accumulated depletion and impairment	(148,948		)	(71,659		)
Oil and natural gas interests, net	$	611,870		$	483,333

Balance of acquisition costs not subject to depletion
Incurred in 2016	$	169,528
Incurred in 2015	$	37,112
Incurred in 2014	$	45,592

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. The impairment charge affected the Partnership’s reported net loss but did not reduce its cash flow. In addition to commodity prices, the Partnership’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods.

Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Debt

DEBT

Credit Agreement-Wells Fargo Bank

The Partnership is a party to a secured revolving credit agreement, dated as of July 8, 2014, as amended, with Wells Fargo Bank, National Association (“Wells Fargo”), as the administrative agent, sole book runner and lead arranger, and certain other lenders party thereto. The credit agreement provides for a revolving credit facility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 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, 2016, the borrowing base was set at $275.0 million. On August 5, 2016, the Partnership repaid $78.0 million of its outstanding borrowings with a portion of the proceeds from the Partnership’s August 2016 public offering of common units and, as of December 31, 2016, the Partnership had $120.5 million outstanding under its credit agreement. Upon completion of the Partnership’s January 2017 underwritten public offering of common units, the Partnership repaid all of the outstanding borrowings under its credit agreement, and as of February 13, 2017, had no borrowings outstanding under this agreement.

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 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to 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 borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. 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 that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of the Partnership and its subsidiary.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, 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 $250.0 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.

The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of any event of default. The Partnership’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2016
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, 2016, the General Partner did not 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”), Diamondback’s equity sponsor, dated as of June 23, 2014 (the “Advisory Services Agreement”), under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the Partnership’s business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. 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 has agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of the General Partner for such services as may be provided by Wexford at the Partnership’s request in connection with future 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 any and all 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 year ended December 31, 2016, the Partnership did not pay any costs under the Advisory Services Agreement. For the years ended December 31, 2015 and 2014, the Partnership incurred costs of $0.5 million and $0.3 million, under the Advisory Services Agreement. At December 31, 2016 and 2015, there were no outstanding amounts payable by the Partnership to Wexford. 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, 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. Shared Services Agreement Effective September 19, 2013, the Predecessor entered into a shared services agreement with Diamondback E&P LLC, a wholly-owned subsidiary of Diamondback. This agreement was terminated in connection with the IPO. Under this agreement, Diamondback E&P LLC provided consulting and administrative services to the Predecessor. The Predecessor incurred a monthly charge for the services of $26,000. For the year ended December 31, 2014, the Partnership incurred costs under this agreement of $0.2 million.

Unit-Based Compensation

12 Months Ended

Dec. 31, 2016

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 9,144,000 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, 2016, 2015 and 2014, the Partnership incurred $3.8 million, $3.9 million and $2.1 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 vest approximately 33% ratably on each of the first three anniversaries of the date of grant or earlier upon a change of control (as defined in the LTIP). All outstanding unit options were amended effective November 29, 2016 to provide that vested unit options will become exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning on the third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before and ending on the date a change of control occurs (the earlier occurring of such events, the “Exercise Period”). At any time within the Exercise Period, if a participant attempts to exercise a vested unit option and the fair market value per unit as of such date is less than the exercise price per option unit, the vested unit option will not be exercisable. At the end of the Exercise Period, any vested unit option that is not exercisable or that has not been exercised will automatically terminate and become 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, 2016:



			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2015	2,500,000		$	26.00
Granted	7,600		$	18.49
Expired/Forfeited	(83,334	)	$	26.00
Outstanding at December 31, 2016	2,424,266		$	—	0.47	$	—
Vested and Expected to Vest at December 31, 2016	2,424,266		$	—	0.47	$	—
Exercisable at December 31, 2016	—		$	—	0.00	$	—

As of December 31, 2016, the unrecognized compensation cost related to unvested unit options was $1.4 million. Such cost is expected to be recognized over a weighted-average period of 0.5 years.

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, 2016:



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2015	25,348		$	16.89
Granted	21,696		$	16.57
Vested	(24,350	)	$	17.27
Forfeited	(1,646	)	$	15.48
Unvested at December 31, 2016	21,048		$	16.23

The aggregate fair value of phantom units that vested during the year ended December 31, 2016 was $0.4 million. As of December 31, 2016, the unrecognized compensation cost related to unvested phantom units was $0.3 million. Such cost is expected to be recognized over a weighted-average period of 1.8 years.

Partners' Capital and Partnership Distributions

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References + Details

Partners' Capital and Partnership Distributions

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

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, 2016, the Partnership had a total of 87,800,356 common units issued and outstanding, of which 72,450,000 common units were owned by Diamondback, representing approximately 83% of the total Partnership units outstanding. Following the Partnership’s January 2017 underwritten public offering of common units, Diamondback owned approximately 74% of the Partnership’s outstanding common units.

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



	Common Units
Balance at December 31, 2015	79,726,006
Common units issued in August 2016 public offering	8,050,000
Common units vested and issued under the LTIP	24,350
Balance at December 31, 2016	87,800,356

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.



Date of Approval	Quarter	Amount per Unit		Distribution 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

Earnings Per Unit

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015 and for the period after the closing of its IPO on June 23, 2014 through December 31, 2014, 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,					June 23 through December 31, 2014
	2016			2015		June 23 through December 31, 2014
	(in thousands, except per unit amounts)
Net income (loss) attributable to the period	$	(10,899	)	$	24,419	$	22,613
Net income per common unit, basic	$	(0.13	)	$	0.31	$	0.29
Net income per common unit, diluted	$	(0.13	)	$	0.31	$	0.29
Weighted-average common units outstanding, basic	83,081			79,717		78,090
Weighted-average common units outstanding, diluted	83,081			79,727		78,102

For the years ended December 31, 2016 and 2015, there were 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	12 Months Ended
Commitments and Contingencies	Dec. 31, 2016
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. Litigation The Partnership filed an action in October 2014 to recover $0.5 million held in escrow in connection with a purchase and sale agreement. The escrow agent interpleaded the funds, and the other parties to the agreement have filed a counterclaim to recover the escrow. Both sides also seek recovery of their attorneys’ fees. The case is expected to be scheduled for trial in the first quarter of 2017. It is not possible to predict the outcome with reasonable certainty, but the Partnership does not believe that an adverse outcome would have a material adverse effect on the Partnership’s financial statements and has not included a loss contingency reserve for this matter.

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS On January 24, 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.6 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance will be used for general partnership purposes, which may include additional acquisitions. On February 3, 2017, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2016 of $0.258 per common unit, payable on February 24, 2017, to unitholders of record at the close of business on February 17, 2017.

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2016

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,
	2016			2015
	(In thousands)
Oil and natural gas interests:
Proved	$	508,586		$	469,663
Unproved	252,232			85,329
Total oil and natural gas interests	760,818			554,992
Accumulated depletion and impairment	(148,948		)	(71,659		)
Net oil and natural gas interests capitalized	$	611,870		$	483,333

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,
	2016		2015		2014
	(In thousands)
Acquisition costs
Proved properties	$	31,441	$	4,121	$	10,879
Unproved properties	174,385		39,786		46,810
Total	$	205,826	$	43,907	$	57,689

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,
	2016			2015			2014
	(In thousands)
Royalty income	$	78,837		$	74,859		$	77,767
Production and ad valorem taxes	(5,544		)	(5,531		)	(5,377		)
Gathering and transportation	(415		)	(259		)	—
Depletion	(29,820		)	(35,436		)	(27,601		)
Impairment	(47,469		)	(3,423		)	—
Results of operations from oil, natural gas and natural gas liquids	$	(4,411	)	$	30,210		$	44,789

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2016, 2015 and 2014 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

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

The changes in estimated proved reserves are as follows:



	Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of December 31, 2013	7,218,080		1,175,123		11,261,585
Purchase of reserves in place	225,217		—		346,123
Extensions and discoveries	6,937,134		1,370,291		9,831,241
Revisions of previous estimates	(693,596	)	112,368		(1,795,981	)
Production	(856,541	)	(144,074	)	(648,808	)
As of December 31, 2014	12,830,294		2,513,708		18,994,160
Purchase of reserves in place	107,072		3,640		430,733
Extensions and discoveries	8,449,586		2,012,599		9,476,316
Revisions of previous estimates	(1,454,037	)	(375,275	)	(3,464,719	)
Production	(1,555,493	)	(238,716	)	(1,128,605	)
As of December 31, 2015	18,377,422		3,915,956		24,307,885
Purchase of reserves in place	1,137,783		436,846		2,315,051
Extensions and discoveries	5,647,430		1,477,074		7,181,625
Revisions of previous estimates	(2,040,713	)	74,023		(5,223,179	)
Production	(1,777,922	)	(327,899	)	(1,490,382	)
As of December 31, 2016	21,344,000		5,576,000		27,091,000

Proved Developed Reserves:
December 31, 2014	6,951,892		1,470,966		10,377,401
December 31, 2015	9,700,000		2,204,951		13,739,050
December 31, 2016	12,332,000		3,247,000		15,933,000

Proved Undeveloped Reserves:
December 31, 2014	5,878,402		1,042,742		8,616,759
December 31, 2015	8,677,422		1,711,005		10,568,835
December 31, 2016	9,012,000		2,329,000		11,158,000

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, 2016, the Partnership’s extensions and discoveries of 8,321 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 2,837 MBoe were primarily due to technical revisions with the remainder due to lower product pricing. The purchase of reserves in place of 1,960 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, 2016, 2015 and 2014.



	December 31,
	2016			2015			2014
	(In thousands)
Future cash inflows	$	948,090		$	912,276		$	1,287,730
Future production taxes	(69,109		)	(61,777		)	(88,559		)
Future state margin tax expenses	(4,615		)	(4,789		)	(9,014		)
Future net cash flows	874,366			845,710			1,190,157
10% discount to reflect timing of cash flows	(461,785		)	(449,947		)	(636,921		)
Standardized measure of discounted future net cash flows	$	412,581		$	395,763		$	553,236

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,
	2016		2015		2014
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	39.64	$	45.03	$	87.33
Natural gas (per Mcf)	$	1.36	$	1.64	$	5.12
Natural gas liquids (per Bbl)	$	11.69	$	11.41	$	27.87

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



	December 31,
	2016			2015			2014
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	395,763		$	553,236		$	327,246
Purchase of minerals in place	23,651			2,963			10,879
Sales of oil and natural gas, net of production costs	(74,628		)	(69,328		)	(72,390		)
Extensions and discoveries	104,451			181,330			287,837
Net changes in prices and production costs	(42,155		)	(269,154		)	(17,266		)
Revisions of previous quantity estimates	(42,883		)	(71,399		)	(28,270		)
Net changes in state margin taxes	51			(1,884		)	(1,650		)
Accretion of discount	39,800			54,911			33,450
Net changes in timing of production and other	8,531			15,088			13,400
Standardized measure of discounted future net cash flows at the end of the period	$	412,581		$	395,763		$	553,236

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL DATA (Unaudited)



	2016
	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
	(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 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



	2015
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
Royalty income	$	16,545	$	19,619	$	18,777	$	19,918
Income from operations	4,764		7,946		6,545		5,120
Net income	5,082		8,045		6,355		4,937
Net income attributable to common limited partners per unit:
Basic	$	0.06	$	0.10	$	0.08	$	0.06
Diluted	$	0.06	$	0.10	$	0.08	$	0.06

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2016
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	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. 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.
Capitalized Interest	Capitalized Interest The Partnership capitalizes interest on expenditures made in connection with acquisitions of unproved properties that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these properties to their intended use. Capitalized interest cannot exceed gross interest expense.
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. Any amounts related to operations for the period in 2014 prior to the closing of the IPO on June 23, 2014 will be included in Diamondback’s unitary filing for this tax.
New Accounting Pronouncements	New Accounting 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 certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, early application permitted for annual reporting period beginning after December 31, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Partnership is currently evaluating the impact of this standard; however, it does not believe this standard will have a material impact on the Partnership’s financial statements. In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, “Interest–Imputation of Interest”. This update requires that debt issuance costs related to a recognized debt liability (except costs associated with revolving debt arrangements) be presented in the balance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount, to simplify the presentation of debt issuance costs. This update is effective for financial statements issued for fiscal years beginning after December 15, 2015. The Partnership retrospectively adopted this new standard effective January 1, 2016. Adoption of this update did not have a material impact on the Partnership’s consolidated financial statements. 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. This update will be effective for public entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. Entities should apply the amendments by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The Partnership will be required to mark its cost method investment to fair value with the adoption of this update. 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. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Partnership is still evaluating the impact of this standard. In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-08, “Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Partnership is currently evaluating the impact, if any, that the adoption of this update will have on the Partnership’s financial position, results of operations and liquidity. In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-09, "Compensation - Stock Compensation". This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Partnership is currently evaluating the impact that the adoption of this update will have on the Partnership's financial position, results of operations and liquidity. In April 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-10, “Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing”. This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity. In May 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-12, “Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients”. This update applies only to the following areas from Accounting Standards Codification Topic 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity. In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affect 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 a material impact on the Partnership’s financial statements since the Partnership does not have a history of credit losses.

Oil and Natural Gas Interests (Tables)

12 Months Ended

Dec. 31, 2016

Aggregate capitalized costs related to oil and natural gas production activities

Oil and natural gas interests include the following:



	December 31,
	2016			2015
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	508,586		$	469,663
Not subject to depletion	252,232			85,329
Gross oil and natural gas interests	760,818			554,992
Accumulated depletion and impairment	(148,948		)	(71,659		)
Oil and natural gas interests, net	$	611,870		$	483,333

Balance of acquisition costs not subject to depletion
Incurred in 2016	$	169,528
Incurred in 2015	$	37,112
Incurred in 2014	$	45,592

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



	December 31,
	2016			2015
	(In thousands)
Oil and natural gas interests:
Proved	$	508,586		$	469,663
Unproved	252,232			85,329
Total oil and natural gas interests	760,818			554,992
Accumulated depletion and impairment	(148,948		)	(71,659		)
Net oil and natural gas interests capitalized	$	611,870		$	483,333

Unit-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016:



			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2015	2,500,000		$	26.00
Granted	7,600		$	18.49
Expired/Forfeited	(83,334	)	$	26.00
Outstanding at December 31, 2016	2,424,266		$	—	0.47	$	—
Vested and Expected to Vest at December 31, 2016	2,424,266		$	—	0.47	$	—
Exercisable at December 31, 2016	—		$	—	0.00	$	—

Schedule of Nonvested Performance-based Units Activity [Table Text Block]

The following table presents the phantom unit activity under the LTIP for the year ended December 31, 2016:



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2015	25,348		$	16.89
Granted	21,696		$	16.57
Vested	(24,350	)	$	17.27
Forfeited	(1,646	)	$	15.48
Unvested at December 31, 2016	21,048		$	16.23

Partners' Capital and Partnership Distributions (Tables)

12 Months Ended

Dec. 31, 2016

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, 2015	79,726,006
Common units issued in August 2016 public offering	8,050,000
Common units vested and issued under the LTIP	24,350
Balance at December 31, 2016	87,800,356

Distributions Made to Limited Partner, by Distribution [Table Text Block]

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



Date of Approval	Quarter	Amount per Unit		Distribution 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

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

12 Months Ended

Dec. 31, 2016

Aggregate capitalized costs related to oil and natural gas production activities

Oil and natural gas interests include the following:



	December 31,
	2016			2015
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	508,586		$	469,663
Not subject to depletion	252,232			85,329
Gross oil and natural gas interests	760,818			554,992
Accumulated depletion and impairment	(148,948		)	(71,659		)
Oil and natural gas interests, net	$	611,870		$	483,333

Balance of acquisition costs not subject to depletion
Incurred in 2016	$	169,528
Incurred in 2015	$	37,112
Incurred in 2014	$	45,592

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



	December 31,
	2016			2015
	(In thousands)
Oil and natural gas interests:
Proved	$	508,586		$	469,663
Unproved	252,232			85,329
Total oil and natural gas interests	760,818			554,992
Accumulated depletion and impairment	(148,948		)	(71,659		)
Net oil and natural gas interests capitalized	$	611,870		$	483,333

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,
	2016		2015		2014
	(In thousands)
Acquisition costs
Proved properties	$	31,441	$	4,121	$	10,879
Unproved properties	174,385		39,786		46,810
Total	$	205,826	$	43,907	$	57,689

Results of Operations for Oil and Gas Producing Activities



	December 31,
	2016			2015			2014
	(In thousands)
Royalty income	$	78,837		$	74,859		$	77,767
Production and ad valorem taxes	(5,544		)	(5,531		)	(5,377		)
Gathering and transportation	(415		)	(259		)	—
Depletion	(29,820		)	(35,436		)	(27,601		)
Impairment	(47,469		)	(3,423		)	—
Results of operations from oil, natural gas and natural gas liquids	$	(4,411	)	$	30,210		$	44,789

Changes in Estimated Proved Reserves

The changes in estimated proved reserves are as follows:



	Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of December 31, 2013	7,218,080		1,175,123		11,261,585
Purchase of reserves in place	225,217		—		346,123
Extensions and discoveries	6,937,134		1,370,291		9,831,241
Revisions of previous estimates	(693,596	)	112,368		(1,795,981	)
Production	(856,541	)	(144,074	)	(648,808	)
As of December 31, 2014	12,830,294		2,513,708		18,994,160
Purchase of reserves in place	107,072		3,640		430,733
Extensions and discoveries	8,449,586		2,012,599		9,476,316
Revisions of previous estimates	(1,454,037	)	(375,275	)	(3,464,719	)
Production	(1,555,493	)	(238,716	)	(1,128,605	)
As of December 31, 2015	18,377,422		3,915,956		24,307,885
Purchase of reserves in place	1,137,783		436,846		2,315,051
Extensions and discoveries	5,647,430		1,477,074		7,181,625
Revisions of previous estimates	(2,040,713	)	74,023		(5,223,179	)
Production	(1,777,922	)	(327,899	)	(1,490,382	)
As of December 31, 2016	21,344,000		5,576,000		27,091,000

Proved Developed Reserves:
December 31, 2014	6,951,892		1,470,966		10,377,401
December 31, 2015	9,700,000		2,204,951		13,739,050
December 31, 2016	12,332,000		3,247,000		15,933,000

Proved Undeveloped Reserves:
December 31, 2014	5,878,402		1,042,742		8,616,759
December 31, 2015	8,677,422		1,711,005		10,568,835
December 31, 2016	9,012,000		2,329,000		11,158,000

Standardized Measure of Discounted Future Net Cash Flows



	December 31,
	2016			2015			2014
	(In thousands)
Future cash inflows	$	948,090		$	912,276		$	1,287,730
Future production taxes	(69,109		)	(61,777		)	(88,559		)
Future state margin tax expenses	(4,615		)	(4,789		)	(9,014		)
Future net cash flows	874,366			845,710			1,190,157
10% discount to reflect timing of cash flows	(461,785		)	(449,947		)	(636,921		)
Standardized measure of discounted future net cash flows	$	412,581		$	395,763		$	553,236

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,
	2016		2015		2014
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	39.64	$	45.03	$	87.33
Natural gas (per Mcf)	$	1.36	$	1.64	$	5.12
Natural gas liquids (per Bbl)	$	11.69	$	11.41	$	27.87

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,
	2016			2015			2014
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	395,763		$	553,236		$	327,246
Purchase of minerals in place	23,651			2,963			10,879
Sales of oil and natural gas, net of production costs	(74,628		)	(69,328		)	(72,390		)
Extensions and discoveries	104,451			181,330			287,837
Net changes in prices and production costs	(42,155		)	(269,154		)	(17,266		)
Revisions of previous quantity estimates	(42,883		)	(71,399		)	(28,270		)
Net changes in state margin taxes	51			(1,884		)	(1,650		)
Accretion of discount	39,800			54,911			33,450
Net changes in timing of production and other	8,531			15,088			13,400
Standardized measure of discounted future net cash flows at the end of the period	$	412,581		$	395,763		$	553,236

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 932
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-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
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-URI http://asc.fasb.org/extlink&oid=34713648&loc=d3e63071-109448

+ Details

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

+ References + Details

Net income (loss) attributable to the period

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

+ References + Details

Organization and Basis of Presentation (Details) - USD ($) $ / shares in Units, $ in Thousands			1 Months Ended	6 Months Ended	12 Months Ended
	Sep. 19, 2014	Jun. 23, 2014	Jan. 31, 2017	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2014
Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering					6,050,000
General Partner [Member]
Limited Partners' Capital Account [Line Items]
Percent of General Partner interest					100.00%
IPO [Member] \| Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering		5,750,000
Price per common unit (in dollars per unit)		$ 26.00
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions		$ 137,237
Over-Allotment Option [Member] \| Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering		750,000
Follow-on Public Offering [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering					8,050,000
Follow-on Public Offering [Member] \| Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering	3,500,000
Price per common unit (in dollars per unit)	$ 28.50
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions	$ 94,800
Diamondback Energy, Inc. [Member] \| Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Conversion of membership interests to common units		70,450,000
Distribution payable		$ 11,300
Distribution of net proceeds to Diamondback				$ 148,800
Diamondback Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Distribution of net proceeds to Diamondback						$ 148,760
Percent of limited partnership interest					83.00%
Diamondback Limited Partner [Member] \| Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering					2,000,000
Distribution of net proceeds to Diamondback						$ 148,760
Subsequent Event [Member] \| Diamondback Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Percent of limited partnership interest			74.00%

Summary of Significant Accounting Policies - Oil and Natural Gas Properties, Capitalized Interest, and Debt Issuance Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) $ / Boe	Dec. 31, 2015 USD ($) $ / Boe	Dec. 31, 2014 USD ($) $ / Boe
Accounting Policies [Abstract]
Average depletion rate per barrel equivalent unit of production \| $ / Boe	12.67	17.88	24.89
Depletion of oil and gas properties	$ 29,820	$ 35,436	$ 27,601
Impairment of oil and gas properties	47,469	3,423	0
Interest costs capitalized	0	0	5,275
Debt issuance costs, net of accumulated amortizations	2,159	1,717	1,277
Debit issuance costs, accumulated amortization	$ 826	$ 425	$ 112

Summary of Significant Accounting Policies - Concentrations and Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Concentration Risk [Line Items]
Restricted cash	$ 500	$ 500
Value of cost method investment			$ 33,900
Shell Trading [Member] \| Customer Concentration Risk [Member] \| Royalty Interest Revenue [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	57.00%	68.00%	70.00%
RSP Permian LLC [Member] \| Customer Concentration Risk [Member] \| Royalty Interest Revenue [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	32.00%	25.00%
Permian Transport & Trading [Member] \| Customer Concentration Risk [Member] \| Royalty Interest Revenue [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue			15.00%
Other assets [Member]
Concentration Risk [Line Items]
Value of cost method investment	$ 33,851

Acquisitions (Details) $ in Thousands	12 Months Ended
Acquisitions (Details) $ in Thousands	Dec. 31, 2016 USD ($) a	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) a
Business Acquisition [Line Items]
Mineral Properties, Gross Acres \| a	61,679		10,364
Mineral Properties, Net Acres \| a	2,142		3,261
Payments to acquire mineral interests	$ 205,721	$ 43,907	$ 57,689
Value of cost method investment			$ 33,900
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 Interests (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Subject to depletion	$ 508,586	$ 469,663
Not subject to depletion	252,232	85,329
Gross oil and natural gas interests	760,818	554,992
Accumulated depletion and impairment	(148,948)	(71,659)
Oil and natural gas interests, net	611,870	483,333
Balance of acquisition costs not subject to depletion	169,528	37,112	$ 45,592
Impairment	$ 47,469	$ 3,423	$ 0
Minimum [Member]
Property, Plant and Equipment [Line Items]
Anticipated number of years for inclusion of costs in amortization calculation	3
Maximum [Member]
Property, Plant and Equipment [Line Items]
Anticipated number of years for inclusion of costs in amortization calculation	5

Debt - Credit Facility (Details) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
Debt - Credit Facility (Details) $ in Thousands	Jan. 31, 2017 USD ($)	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($) redetermindation	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Feb. 13, 2017 USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity			$ 500,000
Number of additional redeterminations that may be requested \| redetermindation			3
Period of redeterminations			12 months
Current borrowing capacity			$ 275,000
Repayments of Lines of Credit		$ 78,000	78,000	$ 0	$ 78,000
Amount outstanding under credit facility			$ 120,500
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			0.50%
Minimum [Member] \| LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate			1.50%
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			1.50%
Maximum [Member] \| LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate			2.50%
Subsequent Event [Member]
Line of Credit Facility [Line Items]
Repayments of Lines of Credit	$ 120,500
Amount outstanding under credit facility						$ 0

Debt - Financial Covenants (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Line of Credit Facility [Line Items]
Maximum issuance of unsecured debt	$ 250,000
Reduction of borrowing base	25.00%
Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX, not greater than 4.0	4.0
Minimum [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, not less than 1.0	1.0

Related Party Transactions (Details)	6 Months Ended	12 Months Ended
Related Party Transactions (Details)	Jun. 22, 2014 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Related Party Transaction [Line Items]
Payments to acquire mineral interests		$ 205,721,000	$ 43,907,000	$ 57,689,000
Amounts owed to related party		0	4,000
General Partner [Member] \| Partnership Agreement [Member]
Related Party Transaction [Line Items]
Incurred costs for transactions with related party		0
Amounts owed to related party				4,000
Affiliated Entity [Member] \| Advisory Services Agreement [Member]
Related Party Transaction [Line Items]
Incurred costs for transactions with related party		0	500,000	300,000
Amounts owed to related party		0	$ 0
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] \| Shared Service Agreement [Member]
Related Party Transaction [Line Items]
Incurred costs for transactions with related party				$ 200,000
Monthly expense for transaction with related party	$ 26,000
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
Diamondback Limited Partner [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties		$ 309,000
Number of leases extended		6
Average price per acre		$ 1,371

Unit-Based Compensation Additional Disclosures (Details) - USD ($) $ in Millions		12 Months Ended
	Jun. 17, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units reserved for issuance		9,144,000
Equity-based compensation		$ 3.8	$ 3.9	$ 2.1
Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit options granted	2,500,000	7,600
Vesting percentage for next three anniversaries	33.00%

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

Unit-Based Compensation Unit Option Activity (Details) - Unit Options [Member] - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
	Jun. 17, 2014	Dec. 31, 2016
Number of Options
Outstanding at December 31, 2015		2,500,000
Granted	2,500,000	7,600
Expired/Forfeited		(83,334)
Outstanding at December 31, 2016		2,424,266
Vested and Expected to Vest at December 31, 2016		2,424,266
Exercisable at December 31, 2016		0
Weighted Average Exercise Price
Outstanding at December 31, 2015		$ 26.00
Granted		18.49
Expired/Forfeited		26.00
Outstanding at December 31, 2016		0.00
Vested and Expected to Vest at December 31, 2016		0.00
Exercisable at December 31, 2016		$ 0.00
Outstanding at end of period, remaining term		5 months 19 days
Vested and expected to vest at end of period, remaining term		5 months 19 days
Exercisable 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
Exercisable at end of period, intrinsic value		0
Unrecognized compensation cost related to unvested unit options		$ 1,400
Unrecognized compensation cost related to unvested unit options, period of recognition		5 months 19 days

Unit-Based Compensation Phantom Units (Details) - Phantom Share Units (PSUs) [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Unvested at December 31, 2015 \| shares	25,348
Granted \| shares	21,696
Vested \| shares	(24,350)
Forfeited \| shares	(1,646)
Unvested at December 31, 2016 \| shares	21,048
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested at December 31, 2015 \| $ / shares	$ 16.89
Granted \| $ / shares	16.57
Vested \| $ / shares	17.27
Forfeited \| $ / shares	15.48
Unvested at December 31, 2016 \| $ / shares	$ 16.23
Equity Instruments Other than Options, Vested in Period, Fair Value \| $	$ 0.4
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized \| $	$ 0.3
Unrecognized compensation cost related to unvested unit options, period of recognition	1 year 9 months 11 days

Partners' Capital and Partnership Distributions (Details) - shares	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Limited Partners' Capital Account [Line Items]
Common units issued		87,800,000	79,726,000
Common units outstanding		87,800,356	79,726,006
Partners' Capital Account, Units, Unit-based Compensation		24,350
Diamondback Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Units of partnership interest		72,450,000
Percent of limited partnership interest		83.00%
Follow-on Public Offering [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering		8,050,000
Subsequent Event [Member] \| Diamondback Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Percent of limited partnership interest	74.00%

Partnership Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
Limited Partners' Capital Account, Distribution Amount									$ 9,574	$ 7,968	$ 2,314
Cash Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Cash distributions, distribution period after quarter end									60 days
Diamondback Limited Partner [Member] \| Cash Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.207		$ 0.149	$ 0.228	$ 0.200	$ 0.220	$ 0.189	$ 0.250
Limited Partners' Capital Account, Distribution Amount	$ 14,997	$ 13,693	$ 10,497	$ 16,063	$ 14,091	$ 15,499	$ 13,385	$ 17,612

Earnings Per Unit (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

6 Months Ended

12 Months Ended

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

Jun. 22, 2014

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Earnings Per Share [Abstract]

$ 16,254

$ 10,202

$ (14,020)

$ (23,335)

$ 4,937

$ 6,355

$ 8,045

$ 5,082

$ 22,613

$ 7,021

$ (10,899)

$ 24,419

$ 29,634

Net income per common unit, basic

$ 0.20

$ 0.12

$ (0.18)

$ (0.29)

$ 0.06

$ 0.08

$ 0.10

$ 0.06

$ (0.13)

$ 0.31

$ 0.29

^[1]

Net income per common unit, diluted

$ 0.20

$ 0.12

$ (0.18)

$ (0.29)

$ 0.06

$ 0.08

$ 0.10

$ 0.06

$ (0.13)

$ 0.31

$ 0.29

^[1]

Weighted-average common units outstanding, basic

83,081,000

79,717,000

78,090,000

^[1]

Weighted-average common units outstanding, diluted

83,081,000

79,727,000

78,102,000

^[1]

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

1,567,155

1,697,142

[1]	2014 information presented is attributable to the period June 23, 2014 through December 31, 2014.

Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Subsequent Event [Line Items]
Repayments of Lines of Credit		$ 78,000	$ 78,000	$ 0	$ 78,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Repayments of Lines of Credit	$ 120,500
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.258
Follow-on Public Offering [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	9,775,000
Sale of Stock, Consideration Received on Transaction	$ 147,600
Over-Allotment Option [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	1,275,000

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, 2016	Dec. 31, 2015
Oil and natural gas interests:
Proved properties	$ 508,586	$ 469,663
Unproved properties	252,232	85,329
Total oil and natural gas interests	760,818	554,992
Accumulated depletion and impairment	(148,948)	(71,659)
Net oil and natural gas interests capitalized	$ 611,870	$ 483,333

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved properties	$ 31,441	$ 4,121	$ 10,879
Unproved properties	174,385	39,786	46,810
Total	$ 205,826	$ 43,907	$ 57,689

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Royalty income	$ 27,923	$ 19,992	$ 16,836	$ 14,086	$ 19,918	$ 18,777	$ 19,619	$ 16,545	$ 78,837	$ 74,859	$ 77,767
Production and ad valorem taxes									(5,544)	(5,531)	(5,377)
Gathering and transportation									(415)	(259)	0
Depletion									(29,820)	(35,436)	(27,601)
Impairment									(47,469)	(3,423)	0
Results of operations from oil, natural gas and natural gas liquids									$ (4,411)	$ 30,210	$ 44,789

Supplemental Information on Oil and Natural Gas Operations (Unaudited) Changes in Estimated Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2016 Mcf bbl	Dec. 31, 2015 well acquisition Mcf bbl	Dec. 31, 2014 Mcf bbl
Reserve Quantities [Line Items]
Purchase of reserves in place	1,960,000
Extensions and discoveries	8,321,000
Revisions of previous estimates	(2,837,000)
Development Wells Drilled, Net Productive	33
Proved Undeveloped Reserves Number of Wells Added	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	18,377,422	12,830,294	7,218,080
Purchase of reserves in place	1,137,783	107,072	225,217
Extensions and discoveries	5,647,430	8,449,586	6,937,134
Revisions of previous estimates	(2,040,713)	(1,454,037)	(693,596)
Production	(1,777,922)	(1,555,493)	(856,541)
End of period	21,344,000	18,377,422	12,830,294
Proved Developed Reserves (Volume)	12,332,000	9,700,000	6,951,892
Proved Undeveloped Reserve (Volume)	9,012,000	8,677,422	5,878,402
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning of the period	3,915,956	2,513,708	1,175,123
Purchase of reserves in place	436,846	3,640	0
Extensions and discoveries	1,477,074	2,012,599	1,370,291
Revisions of previous estimates	74,023	(375,275)	112,368
Production	(327,899)	(238,716)	(144,074)
End of period	5,576,000	3,915,956	2,513,708
Proved Developed Reserves (Volume)	3,247,000	2,204,951	1,470,966
Proved Undeveloped Reserve (Volume)	2,329,000	1,711,005	1,042,742
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of the period \| Mcf	24,307,885	18,994,160	11,261,585
Purchase of reserves in place \| Mcf	2,315,051	430,733	346,123
Extensions and discoveries \| Mcf	7,181,625	9,476,316	9,831,241
Revisions of previous estimates \| Mcf	(5,223,179)	(3,464,719)	(1,795,981)
Production \| Mcf	(1,490,382)	(1,128,605)	(648,808)
End of period \| Mcf	27,091,000	24,307,885	18,994,160
Proved Developed Reserves (Volume) \| Mcf	15,933,000	13,739,050	10,377,401
Proved Undeveloped Reserve (Volume) \| Mcf	11,158,000	10,568,835	8,616,759
Diamondback Energy, Inc. [Member]
Reserve Quantities [Line Items]
Number of Wells Operated by Others \| well		57

Supplemental Information on Oil and Natural Gas Operations (Unaudited) Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Future cash inflows	$ 948,090	$ 912,276	$ 1,287,730
Future production taxes	(69,109)	(61,777)	(88,559)
Future state margin tax expense	(4,615)	(4,789)	(9,014)
Future net cash flows	874,366	845,710	1,190,157
10% discount to reflect timing of cash flows	(461,785)	(449,947)	(636,921)
Standardized measure of discounted future net cash flows	$ 412,581	$ 395,763	$ 553,236	$ 327,246

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, 2016 $ / Mcf $ / bbl	Dec. 31, 2015 $ / Mcf $ / bbl	Dec. 31, 2014 $ / 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	39.64	45.03	87.33
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Unweighted Arithmetic Average First-Day-of-the-Month Prices \| $ / Mcf	1.36	1.64	5.12
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	11.69	11.41	27.87

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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 395,763	$ 553,236	$ 327,246
Purchase of minerals in place	23,651	2,963	10,879
Sales of oil and natural gas, net of production costs	(74,628)	(69,328)	(72,390)
Extensions and discoveries	104,451	181,330	287,837
Net changes in prices and production costs	(42,155)	(269,154)	(17,266)
Revisions of previous quantity estimates	(42,883)	(71,399)	(28,270)
Net changes in state margin taxes	51	(1,884)	(1,650)
Accretion of discount	39,800	54,911	33,450
Net changes in timing of production and other	8,531	15,088	13,400
Standardized measure of discounted future net cash flows at the end of the period	$ 412,581	$ 395,763	$ 553,236

Quarterly Financial Data (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

6 Months Ended

12 Months Ended

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

Jun. 22, 2014

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Royalty income

$ 27,923

$ 19,992

$ 16,836

$ 14,086

$ 19,918

$ 18,777

$ 19,619

$ 16,545

$ 78,837

$ 74,859

$ 77,767

Income (loss) from operations

16,910

10,594

(13,711)

(23,104)

5,120

6,545

7,946

4,764

(9,311)

24,375

40,417