Viper Energy Partners (VNOM) 10-Q 7 Aug 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document	6 Months Ended
	Jun. 30, 2014	Jul. 25, 2014
Document and Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Jun-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'
Entity Registrant Name	'Viper Energy Partners LP	'
Entity Central Index Key	'0001602065	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Units, Units Outstanding	'	76,200,000

Consolidated_Balance_Sheets_Un

Consolidated Balance Sheets (Unaudited) (USD $)	Jun. 30, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:	'		'
Cash	$7,029	[1]	$762	[1]
Royalty income receivable	7,168		9,426	[1]
Other current assets	16		0	[1]
Total current assets	14,213		10,188	[1]
Oil and natural gas interests, based on the full cost method of accounting ($135,642 and $160,302 excluded from depletion at June 30, 2014 and December 31, 2013, respectively)	453,309		448,034	[1]
Accumulated depletion	-16,830		-5,199	[1]
Oil and natural gas interests, net	436,479		442,835	[1]
Total assets	450,692		453,023	[1]
Current liabilities:	'		'
Accounts payable	720		0	[1]
Accounts payable—related party	607		9,779	[1]
Other accrued liabilities	1,434		256	[1]
Distribution payable—related party	11,260		0	[1]
Total current liabilities	14,021		10,035	[1]
Note payable—related party	0		440,000	[1]
Total liabilities	14,021		450,035	[1]
Commitments and contingencies	'		'
Members' equity	0		2,988	[1]
Unitholders’ equity:	'		'
General partner	0		0	[1]
Common units (76,200,000 units issued and outstanding as of June 30, 2014)	436,671		0	[1]
Total unitholders’ equity	436,671		2,988	[1]
Total liabilities and unitholders’ equity/members’ equity	$450,692		$453,023	[1]
[1]	See Note 1 for information regarding the basis of financial statement presentation.

Consolidated_Balance_Sheets_Un1

Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Oil and natural gas interests, based on the full cost method of accounting, amount excluded from depletion	$135,642	$160,302	[1]
Common units issued	76,200,000	'
Common units outstanding	76,200,000	'
[1]	See Note 1 for information regarding the basis of financial statement presentation.

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended				6 Months Ended
In Thousands, except Share data, unless otherwise specified	Jun. 30, 2014		Dec. 31, 2013		Jun. 30, 2014
Income Statement [Abstract]	'		'		'
Royalty income	$17,249	[1]	$14,987	[1]	$33,102	[1]
Expenditures:	'		'		'
Production and ad valorem taxes	1,392	[1]	972	[1]	2,313	[1]
Depletion	6,064	[1]	5,199	[1]	11,631	[1]
General and administrative expenses	219	[1]	0	[1]	285	[1]
General and administrative expenses—related party	78	[1]	87	[1]	156	[1]
Interest expense—related party, net of capitalized interest	5,387	[1]	5,741	[1]	10,755	[1]
Total expenditures	13,140	[1]	11,999	[1]	25,140	[1]
Net income	$4,109	[1]	$2,988	[1]	$7,962	[1]
Net income attributable to common limited partners per unit:	'		'		'
Basic (dollars per unit)	$0.01	[1]	'		$0.01	[1]
Diluted (dollars per unit)	$0.01	[1]	'		$0.01	[1]
Weighted average number of limited partner units outstanding	'		'		'
Basic (in units)	76,200,000	[1]	'		76,200,000	[1]
Diluted (in units)	76,200,000	[1]	'		76,200,000	[1]
[1]	See Note 1 for information regarding the basis of financial statement presentation.

Statement_of_Consolidated_Unit

Statement of Consolidated Unitholders' Equity and Members' Equity (Unaudited) (USD $)		Total		Limited Partner [Member]	Members' Equity [Member]
In Thousands, unless otherwise specified					Predecessor [Member]
Partners' capital at Dec. 31, 2013	[1]	$2,988		'	$2,988
Increase (Decrease) in Partners' Capital [Roll Forward]		'		'	'
Net income		7,021	[1]	'	7,021
Partners' capital at Jun. 22, 2014		'		'	'
Partners' capital at Dec. 31, 2013	[1]	2,988		'	2,988
Increase (Decrease) in Partners' Capital [Roll Forward]		'		'	'
Net income	[1]	7,962		'	'
Contribution of Note Payable to Equity		437,115		'	437,115
Distribution payable to Diamondback		-11,260		'	-11,260
Exchange of Predecessor interests for units		'		435,864	-435,864
Net proceeds from the issuance of common units		137,238		137,238	'
Distribution to Diamondback		-137,500		-137,500	'
Unit-based compensation		128		128	'
Partners' capital at Jun. 30, 2014		436,671		436,671	'
Partners' capital at Jun. 22, 2014		'		'	'
Increase (Decrease) in Partners' Capital [Roll Forward]		'		'	'
Net income		941	[1]	941	'
Partners' capital at Jun. 30, 2014		$436,671		$436,671	'
[1]	See Note 1 for information regarding the basis of financial statement presentation.

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Jun. 30, 2014
Cash flows from operating activities:	'		'
Net income	$2,988	[1]	$7,962	[1]
Adjustments to reconcile net income to net cash provided by operating activities:	'		'
Depletion	5,199	[1]	11,631	[1]
Unit-based compensation expense	0	[1]	128	[1]
Changes in operating assets and liabilities:	'		'
Royalty income receivable	-9,426	[1]	2,258	[1]
Other current assets	0	[1]	-16	[1]
Accounts payable—related party	5,828	[1]	-9,172	[1]
Accounts payable and other accrued liabilities	256	[1]	1,273	[1]
Net cash provided by operating activities	4,845	[1]	14,064	[1]
Cash flows from investing activities:	'		'
Additions to oil and natural gas interests	-4,083	[1]	-5,275	[1]
Net cash used in investing activities	-4,083	[1]	-5,275	[1]
Cash flows from financing activities	'		'
Principal payment on subordinated note	0	[1]	-2,885	[1]
Proceeds from initial public offering	0	[1]	139,035	[1]
Initial public offering costs	0	[1]	-1,172	[1]
Distribution to Diamondback	0	[1]	-137,500	[1]
Net cash used in financing activities	0	[1]	-2,522	[1]
Net increase in cash	762	[1]	6,267	[1]
Cash at beginning of period	0	[1]	762	[1]
Cash at end of period	762	[1]	7,029	[1]
Supplemental disclosure of cash flow information:	'		'
Interest paid, net of capitalized interest	0	[1]	16,496	[1]
Supplemental disclosure of non—cash transactions:	'		'
Mineral interest acquired in exchange for note payable	440,000	[1]	0	[1]
Note payable converted to equity	0	[1]	437,115	[1]
Capitalized interest	$3,951	[1]	$5,275	[1]
[1]	See Note 1 for information regarding the basis of financial statement presentation.

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	6 Months Ended
	Jun. 30, 2014
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 Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc., a Delaware corporation (together with its subsidiaries, “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 “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Viper Energy Partners LP and its consolidated subsidiary, Viper Energy Partners LLC (the “Predecessor”), a Delaware limited liability company.
	Prior to the completion on June 23, 2014 of the Partnership’s initial public offering (the “IPO”) of 5,750,000 common units representing limited partner interests, Diamondback owned all of the general and limited partner interests in the Partnership. On June 23, 2014, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests at a price to the public of $26.00 per common unit, which included 750,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms. We received net 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 Viper Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company, maintained its non-economic general partner interest. 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 approximately $11.3 million and the net proceeds from the IPO. As of June 30, 2014, the Partnership had distributed $137.5 million to Diamondback and the Partnership recorded a payable balance of approximately $11.3 million.
	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.
	As of June 30, 2014, the General Partner held a 100% non-economic general partner interest in the Partnership, and our affiliates had an approximate 93% limited partner interest in the Partnership consisting of Diamondback holding an approximate 92% limited partner interest and Wexford Capital LP (“Wexford”) holding an approximate 1% limited partner interest. 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 our 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. See Note 3—Acquisition. 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 that are generally accepted in the United States. All material intercompany balances and transactions are eliminated in consolidation.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2014
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 we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the financial statements.
	We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider 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 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 and unit–based compensation.
	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 our 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 we believe collection is doubtful. Royalty income receivable outstanding longer than the contractual payment terms are considered past due. We determine any allowance by considering a number of factors, including the length of time royalty income receivable are past due, our 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. We write off specific royalty income receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. We determined that an allowance was unnecessary at both June 30, 2014 and December 31, 2013.
	Fair Value of Financial Instruments
	Our financial instruments consist of cash, receivables, payables and a note payable. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of the instruments. The note payable is carried at cost, which approximates fair value based on borrowing rates available to us for bank loans with similar terms and maturities.
	Oil and Natural Gas Properties
	Oil and natural gas producing activities are accounted for in accordance with the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. At June 30, 2014 and December 31, 2013, 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 $27.44, $27.95 and $27.53 for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, respectively. Depletion for oil and gas properties was $6,064,000, $11,631,000 and $5,199,000 for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, respectively.
	Under the full cost method of accounting, the net book value of oil and natural gas properties, may not exceed a calculated “ceiling”. The ceiling limitation is the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%. Estimated future net cash flows are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production. Any excess of the net book value of proved oil and natural gas properties over the ceiling is charged to expense. No impairment on proved oil and natural gas properties was recorded for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013.
	Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess 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
	We capitalize 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 three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, we capitalized approximately $2,348,000, $5,275,000 and $3,951,000, respectively, of interest expense.
	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
	We are subject to risk resulting from the concentration of our royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the six months ended June 30, 2014, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (70%); and Permian Transport & Trading (12%). For the period from inception (September 18, 2013) to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%); and Permian Transport & Trading (19%). We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
	Earnings Per Unit
	Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.
	Unit–Based Compensation
	Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 8—Unit–Based Compensation.
	Income Taxes
	The Partnership is organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income.
	We are subject to the Texas margin tax. Any amounts related to operations for 2013 or 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 six months ended June 30, 2014 or the period from inception (September 18, 2013) through December 31, 2013, so no amount has been provided in the accompanying financial statements of our Predecessor.

Acquisition

Acquisition	6 Months Ended
	Jun. 30, 2014
Business Combinations [Abstract]	'
Acquisition	'
	ACQUISITION
	On September 19, 2013, Diamondback completed the acquisition of mineral interests underlying approximately 14,804 gross (12,687 net) acres in Midland County, Texas in the Permian Basin for $440 million. As part of the closing of the acquisition, the mineral interests were conveyed from the previous owners to the Predecessor. The mineral interests entitle us to receive an average 21.4% royalty interest on all production from this acreage with no additional future capital or operating expense required. The acquisition was accounted for as an acquisition of assets.

Oil_and_Natural_Gas_Interests

Oil and Natural Gas Interests	6 Months Ended
	Jun. 30, 2014
Extractive Industries [Abstract]	'
Oil and Natural Gas Interests	'
	OIL AND NATURAL GAS INTERESTS
	Oil and natural gas interests include the following:
		June 30,			December 31,
		2014			2013
		(in thousands)
	Oil and natural gas interests:
	Subject to depletion	$	317,667		$	287,732
	Not subject to depletion—acquisition costs
	Incurred in 2014	5,275			—
	Incurred in 2013	130,367			160,302
	Total not subject to depletion	135,642			160,302
	Gross oil and natural gas interests	453,309			448,034
	Less accumulated depletion	(16,830		)	(5,199		)
	Oil and natural gas interests, net	$	436,479		$	442,835
	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 our unevaluated costs into the amortization base is expected to be completed within three to five years.

Debt

Debt	6 Months Ended
	Jun. 30, 2014
Debt Disclosure [Abstract]	'
Debt	'
	DEBT
	Credit Facility-Wells Fargo Bank
	On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo Bank, National Association, or Wells Fargo, as the administrative agent, sole book runner and lead arranger. 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 July 8, 2014, the borrowing base was set at $110.0 million, and Wells Fargo was the only lender under the credit agreement, with a maximum credit amount of $55.0 million. Under the credit agreement, the commitment of the lenders is equal to the lessor of the aggregate maximum credit amounts of the lenders and the borrowing base. As of August 6, 2014, the borrowing base was increased to $110.0 million with Wells Fargo as the only lender under the credit agreement. The Partnership had outstanding borrowings of $50.0 million as of August 6, 2014.
	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 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% 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 paid (a) if 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 subsidiaries.
	The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
	Financial Covenant	Required Ratio
	Ratio of total debt to EBITDAX	Not greater than 4.0 to 1.0
	Ratio of current assets to liabilities, as defined in the credit agreement	Not less than 1.0 to 1.0
	EBITDAX will be annualized beginning with the quarter ending September 30, 2014 and ending with the quarter ended March 31, 2015
	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 revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. 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.
	Subordinated Note
	Effective September 19, 2013, the Predecessor issued a subordinated note to Diamondback for the principal sum of $440.0 million for the royalty interest acquisition discussed in Note 3. In connection with the IPO, the subordinated note was converted to equity. The note bore interest at 7.625% per annum. Interest was due and payable monthly in arrears on the first business day of each calendar month. The unpaid principal balance and all accrued interest on the note were due and payable in full on October 1, 2021. Any indebtedness evidenced by this note was subordinate in the right of payment to any indebtedness outstanding under the Diamondback revolving credit facility. Prior to the completion of the IPO, there was $437.1 million of principal and interest outstanding under this note. We owed $9.7 million of accrued interest as of December 31, 2013, which is included in accounts payable—related party in the accompanying balance sheets.

Fair_Value_Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	FAIR VALUE MEASUREMENTS
	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.
	The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. Our assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. We use appropriate valuation techniques based on available inputs to measure the fair values of our assets and liabilities.
	Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
	Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
	Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
	Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	On July 8, 2014, we entered into a secured revolving credit agreement. See Note 5—Debt. The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.

Related_Party_Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2014
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	RELATED PARTY TRANSACTIONS
	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 (the “Partnership Agreement”), dated June 23, 2014.
	The Partnership Agreement requires us to reimburse the General Partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by our General Partner in connection with operating our business. The Partnership Agreement does not set a limit on the amount of expenses for which our 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 us or on our behalf and expenses allocated to our General Partner by its affiliates. Our General Partner is entitled to determine the expenses that are allocable to us.
	Advisory Services Agreement
	In connection with the closing of the IPO, the Partnership and General Partner entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides us and our General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. The Advisory Services Agreement has a term of two years commencing on June 23, 2014, and will continue 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 we terminate such agreement, we are obligated to pay all amounts due through the remaining term. In addition, we have agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of our General Partner for such services as may be provided by Wexford at our request in connection with future acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to our day-to-day business or operations. We have 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.
	Tax Sharing
	In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement (the “Tax Sharing Agreement”) with Diamondback pursuant to which we will reimburse Diamondback for our share of state and local income and other taxes for which our 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 we may be a member for this purpose, to owe less or no tax. In such a situation, we would reimburse Diamondback for the tax we would have owed had the tax attributes not been available or used for our benefit, even though Diamondback had no cash tax expense for that period.
	Shared service agreements
	Effective September 19, 2013, the Predecessor entered into a shared services agreement with Diamondback E&P LLC, a wholly owned subsidiary of Diamondback Energy, Inc. 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 three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, we incurred costs of $78,000, $156,000 and $87,000, respectively. At June 30, 2014 and December 31, 2013, the Partnership owed Diamondback E&P LLC $607,000 and $87,000, respectively, which amounts are included in accounts payable—related party in the accompanying balance sheets.

UnitBased_Compensation

Unit-Based Compensation	6 Months Ended
	Jun. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Unit-Based Compensation	'
	UNIT–BASED COMPENSATION
	On June 17, 2014, 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 three months and six months ended June 30, 2014, we incurred $128,000 and $128,000, 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, we granted 2,500,000 unit options to our executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the next three anniversaries of the date of grant. In the event the fair market value per unit as of the exercise date is less than the exercise price per option unit then the vested options will automatically terminate and become null and void as of the exercise date.
	The fair value of the unit options on the date of grant is expensed over the applicable vesting period. We estimate the fair values of unit options granted using a Black-Scholes option valuation model, which requires us to make several assumptions. At the time of grant we 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		%
	Expected dividend yield	5.9		%
	Expected term (in years)	3
	Risk-free rate	0.99		%
	The following table presents the unit option activity under the LTIP for the six months ended June 30, 2014:
					Weighted Average
		Unit			Exercise		Remaining	Intrinsic
		Options			Price		Term	Value
							(in years)	(in thousands)
	Outstanding at December 31, 2013	—			$	—
	Granted	2,500,000			$	26
	Outstanding at June 30, 2014	2,500,000			$	26	2.97	$	19,500
	Vested and Expected to vest at June 30, 2014	2,500,000			$	26	2.97	$	19,500
	Exercisable at June 30, 2014	—			$	—	—	$	—
	As of June 30, 2014, the unrecognized compensation cost related to unvested unit options was $10,472,000. Such cost is expected to be recognized over a weighted-average period of 3.0 years.

Partners_Capital_and_Partnersh

Partners' Capital and Partnership Distributions	6 Months Ended
	Jun. 30, 2014
Partners' Capital Notes [Abstract]	'
Partners' Capital and Partnership Distributions	'
	PARTNERS’ CAPITAL AND PARTNERSHIP DISTRIBUTIONS
	The Partnership has general partner and common unit partnership interests. The general partner interest is a non-economic interest and is not entitled to any cash distributions.
	At June 30, 2014, the Partnership had a total of 76,200,000 common units issued and outstanding, of which 70,450,000 common units were owned by Diamondback, representing approximately 92% of the total Partnership units outstanding.
	The board of directors of our 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. Our first distribution, however, will include available cash for the period from June 23, 2014, the date of the close of the IPO, through September 30, 2014. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter will be determined by the board of directors of the General Parter following the end of such quarter. Available cash for each quarter will generally equal 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.

Earnings_Per_Unit

Earnings Per Unit	6 Months Ended
	Jun. 30, 2014
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 of the Partnership after the closing of its IPO on June 23, 2014 through June 30, 2014, since this is the amount of net income that is attributable to the Partnership’s common units.
	The Partnership’s net income is allocated wholly to the common units as the General Partner does not have an economic interest.
	Basic and diluted net income per common unit is calculated by dividing net income by the weighted-average number of common units outstanding during the period.
		June 23, 2014 to
		30-Jun-14
	Net income attributable to the period June 23, 2014 through June 30, 2014	$	941,000
	Net income per common unit, basic	$	0.01
	Net income per common unit, diluted	$	0.01
	Weighted-average common units outstanding, basic	76,200,000
	Weighted-average common units outstanding, diluted	76,200,000

Commitments_and_Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	COMMITMENTS AND CONTINGENCIES
	We could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

Subsequent_Events

Subsequent Events	6 Months Ended
	Jun. 30, 2014
Subsequent Events [Abstract]	'
Subsequent Events	'
	SUBSEQUENT EVENTS
	On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as the administrative agent, sole book runner and lead arranger. See Note 5—Debt for further information.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2014
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 we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the financial statements.
	We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider 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 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 and unit–based compensation.
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 our 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 we believe collection is doubtful. Royalty income receivable outstanding longer than the contractual payment terms are considered past due. We determine any allowance by considering a number of factors, including the length of time royalty income receivable are past due, our 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. We write 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, receivables, payables and a note payable. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of the instruments. The note payable is carried at cost, which approximates fair value based on borrowing rates available to us for bank loans with similar terms and maturities.
Oil and Natural Gas Properties	'
	Oil and Natural Gas Properties
	Oil and natural gas producing activities are accounted for in accordance with the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. At June 30, 2014 and December 31, 2013, 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 $27.44, $27.95 and $27.53 for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, respectively. Depletion for oil and gas properties was $6,064,000, $11,631,000 and $5,199,000 for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, respectively.
	Under the full cost method of accounting, the net book value of oil and natural gas properties, may not exceed a calculated “ceiling”. The ceiling limitation is the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%. Estimated future net cash flows are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production. Any excess of the net book value of proved oil and natural gas properties over the ceiling is charged to expense. No impairment on proved oil and natural gas properties was recorded for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013.
	Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess 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
	We capitalize 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.
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
	We are subject to risk resulting from the concentration of our royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the six months ended June 30, 2014, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (70%); and Permian Transport & Trading (12%). For the period from inception (September 18, 2013) to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%); and Permian Transport & Trading (19%). We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Earnings Per Unit	'
	Earnings Per Unit
	Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.
Unit-based Compensation	'
	–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 8—Unit–Based Compensation.
Income Taxes	'
	Income Taxes
	The Partnership is organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income.
	We are subject to the Texas margin tax. Any amounts related to operations for 2013 or 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.

Oil_and_Natural_Gas_Interests_

Oil and Natural Gas Interests (Tables)	6 Months Ended
	Jun. 30, 2014
Extractive Industries [Abstract]	'
Schedule of oil and natural gas interests	'
	Oil and natural gas interests include the following:
		June 30,			December 31,
		2014			2013
		(in thousands)
	Oil and natural gas interests:
	Subject to depletion	$	317,667		$	287,732
	Not subject to depletion—acquisition costs
	Incurred in 2014	5,275			—
	Incurred in 2013	130,367			160,302
	Total not subject to depletion	135,642			160,302
	Gross oil and natural gas interests	453,309			448,034
	Less accumulated depletion	(16,830		)	(5,199		)
	Oil and natural gas interests, net	$	436,479		$	442,835

Debt_Tables

Debt (Tables)	6 Months Ended
	Jun. 30, 2014
Debt Disclosure [Abstract]	'
Schedule of financial covenants	'
	These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
	Financial Covenant	Required Ratio
	Ratio of total debt to EBITDAX	Not greater than 4.0 to 1.0
	Ratio of current assets to liabilities, as defined in the credit agreement	Not less than 1.0 to 1.0
	EBITDAX will be annualized beginning with the quarter ending September 30, 2014 and ending with the quarter ended March 31, 2015

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule of valuation assumptions	'
		2014
	Grant-date fair value	$	4.24
	Expected volatility	36		%
	Expected dividend yield	5.9		%
	Expected term (in years)	3
	Risk-free rate	0.99		%
Schedule of unit option activity	'
	The following table presents the unit option activity under the LTIP for the six months ended June 30, 2014:
					Weighted Average
		Unit			Exercise		Remaining	Intrinsic
		Options			Price		Term	Value
							(in years)	(in thousands)
	Outstanding at December 31, 2013	—			$	—
	Granted	2,500,000			$	26
	Outstanding at June 30, 2014	2,500,000			$	26	2.97	$	19,500
	Vested and Expected to vest at June 30, 2014	2,500,000			$	26	2.97	$	19,500
	Exercisable at June 30, 2014	—			$	—	—	$	—

Earnings_Per_Unit_Tables

Earnings Per Unit (Tables)	6 Months Ended
	Jun. 30, 2014
Earnings Per Share [Abstract]	'
Schedule of basic and diluted net income per common unit	'
		June 23, 2014 to
		30-Jun-14
	Net income attributable to the period June 23, 2014 through June 30, 2014	$	941,000
	Net income per common unit, basic	$	0.01
	Net income per common unit, diluted	$	0.01
	Weighted-average common units outstanding, basic	76,200,000
	Weighted-average common units outstanding, diluted	76,200,000

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation (Details) (USD $)

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 23, 2014

Jun. 23, 2014

Jun. 23, 2014

Jun. 30, 2014

Jun. 23, 2014

Jun. 23, 2014

Jun. 30, 2014

Jun. 30, 2014

General Partner [Member]

IPO [Member]

IPO [Member]

Over-Allotment Option [Member]

Affiliated Limited Partners [Member]

Diamondback Energy, Inc. [Member]

Diamondback Energy, Inc. [Member]

Diamondback Energy, Inc. [Member]

Wexford [Member]

Limited Partner [Member]

Limited Partner [Member]

Limited Partner [Member]

Limited Partner [Member]

Limited Partner [Member]

Limited Partner [Member]

Limited Partner [Member]

Limited Partners' Capital Account [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Units issued in public offering

'

'

'

5,750,000

'

750,000

'

'

'

'

'

Price per common unit (in dollars per unit)

'

'

'

'

$26

'

'

'

'

'

'

Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions

'

'

'

$137,200,000

'

'

'

'

'

'

'

Conversion of membership interests to common units

'

'

'

'

'

'

'

'

70,450,000

'

'

Distribution to Diamondback

'

'

'

'

'

'

'

'

'

137,500,000

'

Distribution payable

$11,260,000

$0

[1]

'

'

'

'

'

$11,300,000

'

'

'

Percent of General Partner interest

'

'

100.00%

'

'

'

'

'

'

'

'

Percent of limited partnership interest

'

'

'

'

'

'

93.00%

'

'

92.00%

1.00%

[1]

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

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Oil and Natural Gas Properties and Capitalized Interest (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Dec. 31, 2013		Jun. 30, 2014
Accounting Policies [Abstract]	'		'		'
Average depletion rate per barrel equivalent unit of production	27.44		27.53		27.95
Depletion of oil and gas properties	$6,064,000	[1]	$5,199,000	[1]	$11,631,000	[1]
Impairment of oil and gas properties	0		0		0
Interest costs capitalized	$2,348,000		$3,951,000	[1]	$5,275,000	[1]
[1]	See Note 1 for information regarding the basis of financial statement presentation.

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Concentrations (Details) (Customer Concentration Risk [Member], Royalty Interest Revenue [Member])	3 Months Ended	6 Months Ended
	Dec. 31, 2013	Jun. 30, 2014
	purchaser	purchaser
Concentration Risk [Line Items]	'	'
Number of major purchasers	2	2
Shell Trading [Member]	'	'
Concentration Risk [Line Items]	'	'
Percent of total royalty interest revenue	59.00%	70.00%
Permian Transport & Trading [Member]	'	'
Concentration Risk [Line Items]	'	'
Percent of total royalty interest revenue	19.00%	12.00%

Acquisition_Details

Acquisition (Details) (USD $)	3 Months Ended		6 Months Ended		0 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Jun. 30, 2014		Sep. 19, 2013	Sep. 19, 2013	Sep. 19, 2013
					Midland County, Texas [Member]	Midland County, Texas [Member]	Midland County, Texas [Member]
						Diamondback Energy, Inc. [Member]	Diamondback Energy, Inc. [Member]
							acre
Business Acquisition [Line Items]	'		'		'	'	'
Acres of oil and gas property, mineral interest, gross	'		'		'	'	14,804
Acres of oil and gas property, mineral interest, net	'		'		'	'	12,687
Consideration transferred to acquire mineral interests	$440,000	[1]	$0	[1]	'	$440,000	'
Percent of royalty interest	'		'		21.40%	'	'
[1]	See Note 1 for information regarding the basis of financial statement presentation.

Oil_and_Natural_Gas_Interests_1

Oil and Natural Gas Interests (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013		Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Jun. 30, 2014
In Thousands, unless otherwise specified				Incurred in 2014 [Member]	Incurred in 2014 [Member]	Incurred in 2013 [Member]	Incurred in 2013 [Member]	Minimum [Member]	Maximum [Member]
Property, Plant and Equipment [Line Items]	'	'		'	'	'	'	'	'
Subject to depletion	$317,667	$287,732		'	'	'	'	'	'
Total not subject to depletion	135,642	160,302	[1]	5,275	0	130,367	160,302	'	'
Gross oil and natural gas interests	453,309	448,034	[1]	'	'	'	'	'	'
Less accumulated depletion	-16,830	-5,199	[1]	'	'	'	'	'	'
Oil and natural gas interests, net	$436,479	$442,835	[1]	'	'	'	'	'	'
Number of years until unevaluated properties are included in full cost pool	'	'		'	'	'	'	'3 years	'5 years
[1]	See Note 1 for information regarding the basis of financial statement presentation.

Debt_Credit_Facility_Details

Debt - Credit Facility (Details) (Subsequent Event [Member], Wells Fargo [Member], Revolving Credit Agreement [Member], USD $)	0 Months Ended
	Jul. 08, 2014	Aug. 06, 2014	Jul. 08, 2014
	redetermindation
Line of Credit Facility [Line Items]	'	'	'
Maximum borrowing capacity	'	'	$500,000,000
Number of additional redeterminations that may be requested	3	'	'
Period of redeterminations	'12 months	'	'
Current borrowing capacity	'	110,000,000	110,000,000
Maximum credit amount	'	'	55,000,000
Amount outstanding under credit facility	'	$50,000,000	'
Federal Funds Rate [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Basis spread on variable rate	0.50%	'	'
LIBOR, 3-month [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	0.38%	'	'
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%	'	'

Debt_Financial_Covenants_Detai

Debt - Financial Covenants (Details) (Subsequent Event [Member], Wells Fargo [Member], Revolving Credit Agreement [Member], USD $)	Jul. 08, 2014
Subsequent Event [Member] | Wells Fargo [Member] | Revolving Credit Agreement [Member]	'
Line of Credit Facility [Line Items]	'
Ratio of total debt to EBITDAX, not greater than 4.0	4
Ratio of current assets to liabilities, not less than 1.0	1
Maximum issuance of unsecured debt	$250,000,000
Reduction of borrowing base	25.00%

Debt_Subordinated_Note_Details

Debt - Subordinated Note (Details) (Diamondback Energy, Inc. [Member], Subordinated Note [Member], USD $)	Jun. 22, 2014	Dec. 31, 2013	Sep. 19, 2013
In Millions, unless otherwise specified
Diamondback Energy, Inc. [Member] | Subordinated Note [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Principal amount	'	'	$440
Stated interest rate	'	'	7.63%
Long-term debt and interest outstanding	437.1	'	'
Accrued interest	'	$9.70	'

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013		Jun. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014	Jun. 22, 2014
				Wexford [Member]	Diamondback E&P LLC [Member]	Diamondback E&P LLC [Member]	Diamondback E&P LLC [Member]	Predecessor [Member]
				Advisory Services Agreement [Member]	Shared Service Agreement [Member]	Shared Service Agreement [Member]	Shared Service Agreement [Member]	Diamondback E&P LLC [Member]
								Shared Service Agreement [Member]
Related Party Transaction [Line Items]	'	'		'	'	'	'	'
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	'	'	'	'
Monthly expense for transaction with related party	'	'		'	'	'	'	26,000
Incurred costs for transactions with related party	'	'		'	78,000	87,000	156,000	'
Amounts owed to related party	$607,000	$9,779,000	[1]	'	$607,000	$87,000	$607,000	'
[1]	See Note 1 for information regarding the basis of financial statement presentation.

UnitBased_Compensation_Additio

Unit-Based Compensation - Additional Disclosures (Details) (USD $)	3 Months Ended	6 Months Ended			0 Months Ended	6 Months Ended	0 Months Ended
In Thousands, except Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 17, 2014	Jun. 17, 2014	Jun. 30, 2014	Jun. 17, 2014
			LTIP [Member]	LTIP [Member]	Executive Officers of General Partner [Member]	Unit Options [Member]	Unit Options [Member]
					LTIP [Member]		Executive Officers of General Partner [Member]
							LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'	'
Common units reserved for issuance	'	'	'	9,144,000	'	'	'
Equity-based compensation	$128	$128	'	'	'	'	'
Unit options granted	'	'	2,500,000	'	2,500,000	'	'
Vesting percentage for next three anniversaries	'	'	'	'	'	'	33.00%
Unrecognized compensation cost related to unvested unit options	$10,472	$10,472	'	'	'	'	'
Unrecognized compensation cost related to unvested unit options, period of recognition	'	'	'	'	'	'2 years 11 months 18 days	'

UnitBased_Compensation_Valuati

Unit-Based Compensation - Valuation Assumptions (Details) (Unit Options [Member], USD $)	6 Months Ended
	Jun. 30, 2014
Unit Options [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Grant-date fair value (in dollars per share)	$4.24
Expected volatility	36.00%
Expected dividend yield	5.90%
Expected term (in years)	'3 years
Risk-free rate	0.99%

UnitBased_Compensation_Unit_Op

Unit-Based Compensation - Unit Option Activity (Details) (LTIP [Member], USD $)	6 Months Ended
In Thousands, except Share data, unless otherwise specified	Jun. 30, 2014
LTIP [Member]	'
Number of Options	'
Outstanding at December 31, 2013 (units)	0
Granted (units)	2,500,000
Outstanding at June 30, 2014 (units)	2,500,000
Vested and Expected to vest at June 30, 2014 (units)	2,500,000
Exercisable at June 30, 2014 (units)	0
Weighted Average Exercise Price	'
Outstanding at December 31, 2013 (in dollars per unit)	$0
Granted (in dollars per unit)	$26
Outstanding at June 30, 2014 (in dollars per unit)	$26
Vested and Expected to vest at June 30, 2014 (in dollars per unit)	$26
Exercisable at June 30, 2014 (in dollars per unit)	$0
Outstanding at end of period, remaining term	'2 years 11 months 18 days
Vested and expected to vest at end of period, remaining term	'2 years 11 months 18 days
Exercisable at end of period, remaining term	'0 years
Outstanding at end of period, intrinsic value	$19,500
Vested and expected to vest at end of period, intrinsic value	19,500
Exercisable at end of period, intrinsic value	$0

Partners_Capital_and_Partnersh1

Partners' Capital and Partnership Distributions (Details)	6 Months Ended
	Jun. 30, 2014
Limited Partners' Capital Account [Line Items]	'
Common units issued	76,200,000
Common units outstanding	76,200,000
Cash Distribution [Member]	'
Limited Partners' Capital Account [Line Items]	'
Cash distributions, distribution period after quarter end	'60 days
Diamondback Energy, Inc. [Member] | Limited Partner [Member]	'
Limited Partners' Capital Account [Line Items]	'
Units of partnership interest	70,450,000
Percent of limited partnership interest	92.00%

Earnings_Per_Unit_Details

Earnings Per Unit (Details) (USD $)

0 Months Ended

3 Months Ended

6 Months Ended

In Thousands, except Share data, unless otherwise specified

Jun. 30, 2014

Jun. 22, 2014

Jun. 30, 2014

Dec. 31, 2013

Jun. 22, 2014

Jun. 30, 2014

Earnings Per Share [Abstract]

'

'

'

'

'

'

Net income attributable to the period June 23, 2014 through June 30, 2014

$941

[1]

$3,168

[1]

$4,109

[1]

$2,988

[1]

$7,021

[1]

$7,962

[1]

Net income per common unit, basic

$0.01

'

$0.01

[1]

'

'

$0.01

[1]

Net income per common unit, diluted

$0.01

'

$0.01

[1]

'

'

$0.01

[1]

Weighted-average common units outstanding, basic

76,200,000

'

'

'

'

'

Weighted-average common units outstanding, diluted

76,200,000

'

76,200,000

[1]

'

'

76,200,000

[1]

[1]

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