Common units (79,708,888 units issued and outstanding as of December 31, 2014)

2,988

^[1]

Unitholders’ equity:

General partner

^[1]

535,351

^[1]

Total unitholders’ equity/members’ equity

535,351

2,988

^[1]

Total liabilities and unitholders’ equity/members’ equity

$ 537,402

$ 453,023

^[1]

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

Consolidated Balance Sheets (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Statement of Financial Position [Abstract]

Oil and natural gas interests, based on the full cost method of accounting, amount excluded from depletion

$ 91,444

$ 160,302

^[1]

Common units issued

79,708,888

Common units outstanding

79,708,888

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

Consolidated Statements of Operations (USD $)
In Thousands, except Per Share data, unless otherwise specified

3 Months Ended

6 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Income Statement [Abstract]

Royalty income

$ 14,987

^[1]

$ 77,767

Costs and expenses:

Production and ad valorem taxes

972

^[1]

5,377

Depletion

5,199

^[1]

27,601

General and administrative expenses

^[1]

3,198

General and administrative expenses—related party

^[1]

1,174

Total costs and expenses

6,258

^[1]

37,350

Income from operations

8,729

^[1]

40,417

Other income (expense)

Interest expense

^[1]

(487)

Interest expense—related party, net of capitalized interest

(5,741)

^[1]

(10,755)

Other income (expense)

^[1]

459

Total other income (expense), net

(5,741)

^[1]

(10,783)

Net income attributable to common limited partners per unit:

$ 2,988

^[1]

$ 22,613

$ 29,634

Basic (dollars per unit)

$ 0.29

Diluted (dollars per unit)

$ 0.29

Weighted average number of limited partner units outstanding

Basic (in units)

78,090

Diluted (in units)

78,102

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

Statement of Consolidated Unitholders' Equity and Members' Equity (USD $)
In Thousands, unless otherwise specified

Total

Limited Partner [Member]

Members' Equity [Member]

Predecessor [Member]

Diamondback Energy, Inc. [Member]

Limited Partner [Member]

Diamondback Limited Partner [Member]

Partners' capital at Sep. 17, 2013

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

^[1]

$ 2,988

Partners' capital at Dec. 31, 2013

^[1]

2,988

^[1]

2,988

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

Partners' capital at Jun. 22, 2014

7,021

Partners' capital at Dec. 31, 2013

^[1]

2,988

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

Contribution of Note Payable to Equity

29,634

437,115

Exchange of Predecessor interests for units

447,124

(447,124)

Net proceeds from the issuance of common units

232,198

vnom_DistributionToRelatedParty

148,760

Unit-based compensation

2,102

vnom_LimitedPartnersCapitalAccountDistributionAmount-RelatedParty

17,612

vnom_LimitedPartnersCapitalAccountDistributionAmount

2,314

Partners' capital at Dec. 31, 2014

535,351

Partners' capital at Jun. 22, 2014

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

vnom_DistributionToRelatedParty

22,613

148,800

Partners' capital at Dec. 31, 2014

$ 535,351

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

Consolidated Statements of Cash Flows (USD $)
In Thousands, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Cash flows from operating activities:

Adjustments to reconcile net income to net cash provided by operating activities:

$ 2,988

^[1]

$ 29,634

Depletion

5,199

^[1]

27,601

Amortization of debt issuance costs

^[1]

112

Unit-based compensation expense

^[1]

2,102

Changes in operating assets and liabilities:

Restricted Cash

(500)

Royalty income receivable

(9,426)

^[1]

1,187

Other current assets

^[1]

(253)

Accounts payable—related party

5,828

^[1]

(9,779)

Accounts payable and other accrued liabilities

256

^[1]

1,709

Net cash provided by operating activities

4,845

^[1]

51,813

Cash flows from investing activities:

Additions to oil and natural gas interests

(4,083)

^[1]

(5,276)

Acquisition of mineral interests

^[1]

(57,689)

Cost method investment

^[1]

(33,850)

Net cash used in investing activities

(4,083)

^[1]

(96,815)

Cash flows from financing activities

Proceeds from borrowings on credit facility

^[1]

78,000

Repayment on credit facility

^[1]

(78,000)

Principal payment on subordinated note

^[1]

(2,885)

Debt issuance costs

^[1]

(1,277)

Proceeds from public offerings

^[1]

234,546

Public offering costs

^[1]

(2,348)

Distribution to Diamondback

^[1]

(148,760)

Distribution to limited partners

(19,926)

Net cash provided by financing activities

^[1]

59,350

Net increase in cash

762

^[1]

14,348

Cash at beginning of period

^[1]

762

^[1]

Cash and cash equivalents at end of period

762

^[1]

15,110

Supplemental disclosure of cash flow information:

Interest paid, net of capitalized interest

^[1]

16,983

Supplemental disclosure of non—cash transactions:

Mineral interest acquired in exchange for note payable

440,000

^[1]

Note payable converted to equity

^[1]

437,115

Capitalized interest

$ 3,951

^[1]

$ 5,275

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

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 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 (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 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 $11.6 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 net 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, 2014, the General Partner held a 100% non-economic general partner interest in the Partnership and Diamondback had an approximate 88.4% limited partner interest in the Partnership. 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. See Note 3—Acquisitions. 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.

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References+ Details

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 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 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 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. 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 $500,000 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, 2014 and December 31, 2013. Fair Value of Financial Instruments Our financial instruments consist of cash and cash equivalents, receivables, payables, credit agreement and, at December 31, 2013, a note payable. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The note payable was carried at cost, which approximated fair value based on borrowing rates available to the Partnership 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 December 31, 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 $24.95 and $27.53 for the year ended December 31, 2014 and for the period from inception to December 31, 2013, respectively. Depletion for oil and gas properties was $27.6 million and $5.2 million for the year ended December 31, 2014 and for the period from inception 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 year ended December 31, 2014 and for the period from inception to December 31, 2013. 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 and for the period from inception to December 31, 2013, the Partnership capitalized approximately $5.3 million and $4.0 million, respectively, of interest expense. Debt Issuance Costs Other assets include capitalized costs of $1.2 million, net of accumulated amortization of $0.1 million as of December 31, 2014. The Partnership did not have any debt issuance costs as of December 31, 2013. 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, 2014, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (70%) and Permian Transport & Trading (15%). For the period from inception to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%) and Permian Transport & Trading (19%). The Partnership does not require collateral and do 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, 2014, 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 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 year ended December 31, 2014 or the period from inception through December 31, 2013, 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 (“ASU”) 2014-09, “Revenue from Contracts with Customers”. ASU 2014-09 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, 2016, with early application not permitted. 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, if any, that the adoption of ASU 2014-09 will have on the Partnership’s financial position, results of operations, and liquidity.

The entire disclosure for all significant accounting policies of the reporting entity.

+ References+ Details

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions	ACQUISITIONS 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. 2013 Activity 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 $440.0 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 the Partnership to receive a 21.4% royalty interest on an average weighted basis from this acreage. The acquisition was accounted for as an acquisition of assets.

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

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+ Details

Oil and Natural Gas Interests

12 Months Ended

Dec. 31, 2014

Oil and Natural Gas Interests

OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:




	December 31,
	2014			2013

	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	419,641		$	287,732
Not subject to depletion—acquisition costs
Incurred in 2014	48,266			—
Incurred in 2013	43,178			160,302
Total not subject to depletion	91,444			160,302

Gross oil and natural gas interests	511,085			448,034
Less accumulated depletion	(32,800		)	(5,199		)
Oil and natural gas interests, net	$	478,285		$	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 the Partnership’s unevaluated costs into the amortization base is expected to be completed within three to five years.

Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt

DEBT

Credit Agreement-Wells Fargo Bank

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo Bank, National Association, or Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement, which was amended August 15, 2014 to add additional lenders to the lending group, 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, 2014, the borrowing base was set at $110.0 million. The Partnership had no outstanding borrowings as of December 31, 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 subsidiary.

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 ended September 30, 2014 and ending with the quarter ending 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 credit agreement 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 credit agreement. Prior to the completion of the IPO, there was $437.1 million of principal and interest outstanding under this note. The Partnership owed $9.7 million of accrued interest as of December 31, 2013, which is included in accounts payable—related party in the accompanying consolidated balance sheets.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 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 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, 2014, the Partnership reimbursed the General Partner $0.9 million. At December 31, 2014, the Partnership owed the General Partner approximately $4,000. 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 Capital LP (“Wexford”), Diamondback’s equity sponsor, dated as of June 23, 2014, 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 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 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, 2014, we incurred costs of $0.3 million, under the Advisory Services Agreement. At December 31, 2014, there were no outstanding amounts payable by the Partnership to Wexford. 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 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, 2014, the Partnership reimbursed the General Partner $0.9 million. At December 31, 2014, the Partnership owed the General Partner approximately $4,000. 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 Capital LP (“Wexford”), Diamondback’s equity sponsor, dated as of June 23, 2014, 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 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 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, 2014, we incurred costs of $0.3 million, under the Advisory Services Agreement. At December 31, 2014, 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 (the “Tax Sharing Agreement”) with Diamondback pursuant to which the Partnership will 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 would 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. 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 and for the period from inception to December 31, 2013, the Partnership incurred costs under this agreement of $156,000 and $87,000, respectively. At December 31, 2013, the Partnership owed Diamondback E&P LLC $87,000, which is included in accounts payable—related party in the accompanying consolidated balance sheets.

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

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

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Unit-Based Compensation

12 Months Ended

Dec. 31, 2014

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 year ended December 31, 2014, the Partnership incurred $2.1 million 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 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, 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. 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, 2014:



		Weighted Average
	Unit	Exercise		Remaining	Intrinsic
	Options	Price		Term	Value
				(in years)	(in thousands)
Outstanding at December 31, 2013	—	$	—
Granted	2,500,000	$	26.00
Outstanding at December 31, 2014	2,500,000	$	26.00	2.47	$	—

Vested and Expected to vest at December 31, 2014	2,500,000	$	26.00	2.47	$	—
Exercisable at December 31, 2014	—	$	—	—	$	—

As of December 31, 2014, the unrecognized compensation cost related to unvested unit options was $8.7 million. Such cost is expected to be recognized over a weighted-average period of 2.5 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 values 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 unit entitles the recipient 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, 2014:



			Weighted Average
	Phantom		Grant-Date
	Units		Fair Value
Unvested at December 31, 2013	—		$	—
Granted	26,664		$	19.51
Vested	(8,888	)	$	19.51
Unvested at December 31, 2014	17,776		$	19.51

The aggregate fair value of phantom units that vested during the year ended December 31, 2014 was $0.2 million. As of December 31, 2014, 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 1.5 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.

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Partners' Capital and Partnership Distributions

12 Months Ended

Dec. 31, 2014

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, 2014, the Partnership had a total of 79,708,888 common units issued and outstanding, of which 70,450,000 common units were owned by Diamondback, representing approximately 88.4% of the total Partnership units outstanding.

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



		Common Units

Diamondback Energy, Inc. ownership of common units		70,450,000
Common units issued in June 23, 2014 IPO		5,750,000
Common units issued in September 19, 2014 public offering		3,500,000
Common units vested and issued under the LTIP in 2014		8,888
Balance December 31, 2014		79,708,888

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. Our first distribution, however, included available cash for the period from June 23, 2014, the date of the close of the IPO, through September 30, 2014. On November 4, 2014, the board of directors of the General Partner approved a cash distribution attributable to the period from June 23, 2014 through September 30, 2014 of $0.25 per unit, which was paid on November 28, 2014. This distribution included a total of $17.6 million distributed to Diamondback. 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 Partner 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 the General Partner deems necessary or appropriate, if any.

The entire disclosure for the formation, structure, control and ownership of the partnership. Disclosures related to accounts comprising partners' capital. Includes balances of general partners' capital account, limited partners' capital account, preferred partners' capital account and total partners' capital account and units outstanding; accumulated other comprehensive income; amount and nature of changes to amount of partner's capital and units outstanding by class, rights and privileges for each class of units; distribution policies and distributions paid by unit class; impact of and correction of an error in previously issued financial statements; limitations of partners' liability; redemption, conversion and distribution policies; and deferred compensation related to the issuance of units.

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Earnings Per Unit

12 Months Ended

Dec. 31, 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 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 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 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,
		2014^¬


Net income		$	22,613
Net income per common unit, basic		$	0.29
Net income per common unit, diluted		$	0.29
Weighted-average common units outstanding, basic		78,090
Weighted-average common units outstanding, diluted		78,102

¬	Net income attributable to the period June 23, 2014 through December 31, 2014

The entire disclosure for earnings per share.

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Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2014
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.

The entire disclosure for commitments and contingencies.

+ References+ Details

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

12 Months Ended

Dec. 31, 2014

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,
	2014			2013

	(In thousands)
Oil and natural gas interests:
Proved	$	419,641		$	287,732
Unproved	91,444			160,302
Total oil and natural gas interests	511,085			448,034
Less accumulated depletion	(32,800		)	(5,199		)
Net oil and natural gas interests capitalized	$	478,285		$	442,835

Costs incurred in oil and natural gas activities

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



			Period From Inception Through
	Year Ended December 31,		Period From Inception Through
	2014		December 31, 2013

	(In thousands)
Acquisition costs
Proved	$	10,879	$	200,309
Unproved	46,810		247,725
Total	$	57,689	$	448,034

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.



				Period From Inception Through
	Year Ended December 31,			Period From Inception Through
	2014			December 31, 2013

	(In thousands)
Royalty income	$	77,767		$	14,987
Production and ad valorem taxes	(5,377		)	(972		)
Depletion	(27,601		)	(5,199		)
Results of operations from oil, natural gas and natural gas liquids	$	44,789		$	8,816

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2014 and 2013 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:



			Natural Gas
	Oil		Liquids		Natural Gas
	(Bbls)		(Bbls)		(Mcf)
Proved Developed and Undeveloped Reserves:

Balance at inception	—		—		—

Purchase of reserves in place	5,725,640		1,672,824		7,418,633
Extensions and discoveries	1,724,366		364,047		2,403,261
Revisions of previous estimates	(81,111	)	(841,777	)	1,547,955
Production	(150,815	)	(19,971	)	(108,264	)
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

Proved Developed Reserves:
December 31, 2013	3,692,207		609,303		6,280,409
December 31, 2014	6,951,892		1,470,966		10,377,401

Proved Undeveloped Reserves:
December 31, 2013	3,525,873		565,820		4,981,176
December 31, 2014	5,878,402		1,042,742		8,616,759

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.

Purchases of reserves were primarily from two acquisitions, one in the Midland Basin and one in the Delaware Basin, consisting of 11 vertical wells and two horizontal wells. 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 63 horizontal wells, of which 37 horizontal wells are in the proved undeveloped category. Diamondback is the operator of 49 of the 64 total wells. Revisions are primarily the result of downgrading 29 vertical wells that were classified as PUDs into the probable category as a result of 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, 2014 and 2013.



	December 31,
	2014			2013

	(In thousands)
Future cash inflows	$	1,287,730		$	770,528
Future production taxes	(88,559		)	(53,040		)
Future state margin tax expenses	(9,014		)	(5,394		)

Future net cash flows	1,190,157			712,094
10% discount to reflect timing of cash flows	(636,921		)	(384,848		)

Standardized measure of discounted future net cash flows	$	553,236		$	327,246

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,
	2014		2013

	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	87.33	$	92.64
Natural gas (per Mcf)	$	5.12	$	5.03
Natural gas liquids (per Bbl)	$	27.87	$	38.45

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



				Period From Inception Through
	Year Ended December 31,			Period From Inception Through
	2014			December 31, 2013

	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	327,246		$	—
Purchase of minerals in place	10,879			249,831
Sales of oil and natural gas, net of production costs	(72,390		)	(14,015		)
Extensions and discoveries	287,837			79,829
Net changes in prices and production costs	(17,266		)	24,724
Revisions of previous quantity estimates	(28,270		)	(19,383		)
Net changes in state margin taxes	(1,650		)	(586		)
Accretion of discount	33,450			7,103
Net changes in timing of production and other	13,400			(257		)

Standardized measure of discounted future net cash flows at the end of the period	$	553,236		$	327,246

Quarterly Financial Data (Unaudited) (Notes)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL DATA (Unaudited)



	2014
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter

	(In thousands, except per unit amounts)
Royalty income	$	15,853	$	17,249	$	22,767	$	21,898
Income from operations	9,221		9,496		11,175		10,525
Net income	3,853		4,109		10,869		10,803
Net income attributable to common limited partners			941		10,869		10,803
Net income attributable to common limited partners per unit:
Basic			$	0.01	$	0.14	$	0.14
Diluted			$	0.01	$	0.14	$	0.14



	Period From Inception
	Through
	December 31,
	2013
	(In thousands)
Royalty income	$	14,987
Income from operations	8,729
Net income	2,988

As discussed in Note 1, the results prior to the IPO reflect the results of the Predecessor.

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

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Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 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 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 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.
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, credit agreement and, at December 31, 2013, a note payable. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The note payable was carried at cost, which approximated fair value based on borrowing rates available to the Partnership 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 December 31, 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 $24.95 and $27.53 for the year ended December 31, 2014 and for the period from inception to December 31, 2013, respectively. Depletion for oil and gas properties was $27.6 million and $5.2 million for the year ended December 31, 2014 and for the period from inception 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 year ended December 31, 2014 and for the period from inception to December 31, 2013. 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. During the year ended December 31, 2014 and for the period from inception to December 31, 2013, the Partnership capitalized approximately $5.3 million and $4.0 million, respectively, of interest expense.
Debt Issuance Costs	Debt Issuance Costs Other assets include capitalized costs of $1.2 million, net of accumulated amortization of $0.1 million as of December 31, 2014. The Partnership did not have any debt issuance costs as of December 31, 2013. 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. For the year ended December 31, 2014, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (70%) and Permian Transport & Trading (15%). For the period from inception to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%) and Permian Transport & Trading (19%). The Partnership does not require collateral and do 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 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.
New Accounting Pronouncements	New Accounting Pronouncements In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers”. ASU 2014-09 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, 2016, with early application not permitted. 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, if any, that the adoption of ASU 2014-09 will have on the Partnership’s financial position, results of operations, and liquidity.

Oil and Natural Gas Interests (Tables)

12 Months Ended

Dec. 31, 2014

Aggregate capitalized costs related to oil and natural gas production activities

Oil and natural gas interests include the following:




	December 31,
	2014			2013

	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	419,641		$	287,732
Not subject to depletion—acquisition costs
Incurred in 2014	48,266			—
Incurred in 2013	43,178			160,302
Total not subject to depletion	91,444			160,302

Gross oil and natural gas interests	511,085			448,034
Less accumulated depletion	(32,800		)	(5,199		)
Oil and natural gas interests, net	$	478,285		$	442,835

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



	December 31,
	2014			2013

	(In thousands)
Oil and natural gas interests:
Proved	$	419,641		$	287,732
Unproved	91,444			160,302
Total oil and natural gas interests	511,085			448,034
Less accumulated depletion	(32,800		)	(5,199		)
Net oil and natural gas interests capitalized	$	478,285		$	442,835

Unit-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014:



		Weighted Average
	Unit	Exercise		Remaining	Intrinsic
	Options	Price		Term	Value
				(in years)	(in thousands)
Outstanding at December 31, 2013	—	$	—
Granted	2,500,000	$	26.00
Outstanding at December 31, 2014	2,500,000	$	26.00	2.47	$	—

Vested and Expected to vest at December 31, 2014	2,500,000	$	26.00	2.47	$	—
Exercisable at December 31, 2014	—	$	—	—	$	—

Partners' Capital and Partnership Distributions (Tables)

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Schedule of changes in common units

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



		Common Units

Diamondback Energy, Inc. ownership of common units		70,450,000
Common units issued in June 23, 2014 IPO		5,750,000
Common units issued in September 19, 2014 public offering		3,500,000
Common units vested and issued under the LTIP in 2014		8,888
Balance December 31, 2014		79,708,888

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

12 Months Ended

Dec. 31, 2014

Aggregate capitalized costs related to oil and natural gas production activities

Oil and natural gas interests include the following:




	December 31,
	2014			2013

	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	419,641		$	287,732
Not subject to depletion—acquisition costs
Incurred in 2014	48,266			—
Incurred in 2013	43,178			160,302
Total not subject to depletion	91,444			160,302

Gross oil and natural gas interests	511,085			448,034
Less accumulated depletion	(32,800		)	(5,199		)
Oil and natural gas interests, net	$	478,285		$	442,835

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



	December 31,
	2014			2013

	(In thousands)
Oil and natural gas interests:
Proved	$	419,641		$	287,732
Unproved	91,444			160,302
Total oil and natural gas interests	511,085			448,034
Less accumulated depletion	(32,800		)	(5,199		)
Net oil and natural gas interests capitalized	$	478,285		$	442,835

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:



			Period From Inception Through
	Year Ended December 31,		Period From Inception Through
	2014		December 31, 2013

	(In thousands)
Acquisition costs
Proved	$	10,879	$	200,309
Unproved	46,810		247,725
Total	$	57,689	$	448,034

Results of Operations for Oil and Gas Producing Activities



				Period From Inception Through
	Year Ended December 31,			Period From Inception Through
	2014			December 31, 2013

	(In thousands)
Royalty income	$	77,767		$	14,987
Production and ad valorem taxes	(5,377		)	(972		)
Depletion	(27,601		)	(5,199		)
Results of operations from oil, natural gas and natural gas liquids	$	44,789		$	8,816

Changes in Estimated Proved Reserves

The changes in estimated proved reserves are as follows:



			Natural Gas
	Oil		Liquids		Natural Gas
	(Bbls)		(Bbls)		(Mcf)
Proved Developed and Undeveloped Reserves:

Balance at inception	—		—		—

Purchase of reserves in place	5,725,640		1,672,824		7,418,633
Extensions and discoveries	1,724,366		364,047		2,403,261
Revisions of previous estimates	(81,111	)	(841,777	)	1,547,955
Production	(150,815	)	(19,971	)	(108,264	)
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

Proved Developed Reserves:
December 31, 2013	3,692,207		609,303		6,280,409
December 31, 2014	6,951,892		1,470,966		10,377,401

Proved Undeveloped Reserves:
December 31, 2013	3,525,873		565,820		4,981,176
December 31, 2014	5,878,402		1,042,742		8,616,759

Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Partnership’s proved oil and natural gas reserves as of December 31, 2014 and 2013.



	December 31,
	2014			2013

	(In thousands)
Future cash inflows	$	1,287,730		$	770,528
Future production taxes	(88,559		)	(53,040		)
Future state margin tax expenses	(9,014		)	(5,394		)

Future net cash flows	1,190,157			712,094
10% discount to reflect timing of cash flows	(636,921		)	(384,848		)

Standardized measure of discounted future net cash flows	$	553,236		$	327,246

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,
	2014		2013

	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	87.33	$	92.64
Natural gas (per Mcf)	$	5.12	$	5.03
Natural gas liquids (per Bbl)	$	27.87	$	38.45

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:



				Period From Inception Through
	Year Ended December 31,			Period From Inception Through
	2014			December 31, 2013

	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	327,246		$	—
Purchase of minerals in place	10,879			249,831
Sales of oil and natural gas, net of production costs	(72,390		)	(14,015		)
Extensions and discoveries	287,837			79,829
Net changes in prices and production costs	(17,266		)	24,724
Revisions of previous quantity estimates	(28,270		)	(19,383		)
Net changes in state margin taxes	(1,650		)	(586		)
Accretion of discount	33,450			7,103
Net changes in timing of production and other	13,400			(257		)

Standardized measure of discounted future net cash flows at the end of the period	$	553,236		$	327,246

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

+ References+ Details

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

+ References

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+ 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

Average depletion rate per barrel equivalent unit of production

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 $)	12 Months Ended	0 Months Ended		0 Months Ended			12 Months Ended		0 Months Ended	6 Months Ended	12 Months Ended
	Dec. 31, 2014 General Partner [Member]	Jun. 23, 2014 IPO [Member] Limited Partner [Member]	Jun. 23, 2014 IPO [Member] Limited Partner [Member]	Jun. 23, 2014 Over-Allotment Option [Member] Limited Partner [Member]	Sep. 19, 2014 Public Offering [Member] Limited Partner [Member]	Sep. 19, 2014 Public Offering [Member] Limited Partner [Member]	Dec. 31, 2014 Diamondback Energy, Inc. [Member]	Jun. 23, 2014 Diamondback Energy, Inc. [Member]	Jun. 23, 2014 Diamondback Energy, Inc. [Member] Limited Partner [Member]	Dec. 31, 2014 Diamondback Energy, Inc. [Member] Limited Partner [Member]	Dec. 31, 2014 Diamondback Energy, Inc. [Member] Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Units issued in public offering		5,750,000		750,000	3,500,000
Price per common unit (in dollars per unit)			$ 26.00			$ 28.5
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions		$ 137,200,000			$ 94,800,000
Conversion of membership interests to common units									70,450,000
Distribution payable								11,600,000
vnom_DistributionToRelatedParty							$ 148,760,000			$ 148,800,000	$ 148,760,000
Percent of General Partner interest	100.00%
Percent of limited partnership interest											88.00%

Summary of Significant Accounting Policies - Oil and Natural Gas Properties, Capitalized Interest, and Debt Issuance Costs (Details) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Accounting Policies [Abstract]

27.53

24.95

Depletion of oil and gas properties

$ 5,199,000

^[1]

$ 27,601,000

Impairment of oil and gas properties

Interest costs capitalized

3,951,000

^[1]

5,275,000

Debt issuance costs, net of accumulated amortizations

1,165,000

Debt issuance costs, accumulated amortization

$ (112,000)

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

Summary of Significant Accounting Policies - Concentrations and Investments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Dec. 31, 2013 purchaser	Dec. 31, 2014 purchaser
Concentration Risk [Line Items]
Value of cost method investment		$ 33.9
Customer Concentration Risk [Member] \| Royalty Interest Revenue [Member]
Concentration Risk [Line Items]
Number of major purchasers	2	2
Shell Trading [Member] \| Customer Concentration Risk [Member] \| Royalty Interest Revenue [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	59.00%	70.00%
Permian Transport & Trading [Member] \| Customer Concentration Risk [Member] \| Royalty Interest Revenue [Member]
Concentration Risk [Line Items]
Percent of total royalty interest revenue	19.00%	15.00%
Other assets [Member]
Concentration Risk [Line Items]
Value of cost method investment		$ 33.9

Acquisitions (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Midland and Delaware Basin [Member]

acre

Sep. 19, 2013

Midland County, Texas [Member]

Sep. 19, 2013

Midland County, Texas [Member]

Diamondback Energy, Inc. [Member]

Sep. 19, 2013

Midland County, Texas [Member]

Diamondback Energy, Inc. [Member]

acre

Business Acquisition [Line Items]

Acres of oil and gas property, mineral interest, gross

10,364

14,804

Acres of oil and gas property, mineral interest, net

3,261

12,687

Payments to acquire mineral interests

$ 0

^[1]

$ 57,689,000

$ 57,700,000

Value of cost method investment

33,900,000

Consideration transferred to acquire mineral interests

$ 440,000,000

^[1]

$ 0

$ 440,000,000

Percent of royalty interest

21.40%

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

Oil and Natural Gas Interests (Details) (USD $)
In Thousands, unless otherwise specified

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Incurred in 2014 [Member]

Dec. 31, 2013

Incurred in 2014 [Member]

Dec. 31, 2014

Incurred in 2013 [Member]

Dec. 31, 2013

Incurred in 2013 [Member]

Dec. 31, 2014

Minimum [Member]

Dec. 31, 2014

Maximum [Member]

Property, Plant and Equipment [Line Items]

Subject to depletion

$ 419,641

$ 287,732

Total not subject to depletion

91,444

160,302

^[1]

48,266

43,178

160,302

Gross oil and natural gas interests

511,085

448,034

^[1]

Less accumulated depletion

(32,800)

(5,199)

^[1]

Oil and natural gas interests, net

$ 478,285

$ 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) (Wells Fargo [Member], Revolving Credit Agreement [Member], USD $)	12 Months Ended
	Dec. 31, 2014 redetermindation	Jul. 08, 2014
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
Amount outstanding under credit facility	$ 0
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	0.375%
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%

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References+ Details

Debt - Financial Covenants (Details) (Wells Fargo [Member], Revolving Credit Agreement [Member], USD $)	Dec. 31, 2014
Wells Fargo [Member] \| Revolving Credit Agreement [Member]
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX, not greater than 4.0	4.0
Ratio of current assets to liabilities, not less than 1.0	1.0
Maximum issuance of unsecured debt	$ 250,000,000
Reduction of borrowing base	25.00%

Debt - Subordinated Note (Details) (Diamondback Energy, Inc. [Member], Subordinated Note [Member], USD $)	Jun. 22, 2014	Dec. 31, 2013	Sep. 19, 2013
Diamondback Energy, Inc. [Member] \| Subordinated Note [Member]
Debt Instrument [Line Items]
Principal amount			$ 440,000,000
Stated interest rate			7.625%
Long-term debt and interest outstanding	437,100,000
Accrued interest		$ 9,700,000

Carrying value as of the balance sheet date of [accrued] interest payable on all forms of debt, including trade payables, that has been incurred and is unpaid. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

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Fair Value Measurements (Details) (Wells Fargo [Member], Revolving Credit Agreement [Member], USD $)	Dec. 31, 2014
Wells Fargo [Member] \| Revolving Credit Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Amount outstanding under credit facility	$ 0

Advisory services agreement, annual fee

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Related Party Transactions (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

6 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

General Partner [Member]

Partnership Agreement [Member]

Sep. 30, 2014

Wexford [Member]

Advisory Services Agreement [Member]

Dec. 31, 2014

Wexford [Member]

Advisory Services Agreement [Member]

Dec. 31, 2013

Diamondback E&P LLC [Member]

Shared Service Agreement [Member]

Dec. 31, 2014

Diamondback E&P LLC [Member]

Shared Service Agreement [Member]

Jun. 22, 2014

Predecessor [Member]

Diamondback E&P LLC [Member]

Shared Service Agreement [Member]

$ 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

906,000

268,000

87,000

156,000

Amounts owed to related party

$ 0

$ 9,779,000

^[1]

$ 4,000

$ 0

$ 87,000

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

Amount for accounts payable to related parties. Used to reflect the current portion of the liabilities (due within one year or within the normal operating cycle if longer).

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Unit-Based Compensation - Additional Disclosures (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended			0 Months Ended	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2014 LTIP [Member]	Jun. 17, 2014 LTIP [Member]	Jun. 17, 2014 Executive Officers of General Partner [Member] LTIP [Member]	Dec. 31, 2014 Unit Options [Member]	Jun. 17, 2014 Unit Options [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	$ 2,102
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	$ 8,706
Unrecognized compensation cost related to unvested unit options, period of recognition					2 years 5 months 18 days

Unit-Based Compensation - Valuation Assumptions (Details) (Unit Options [Member], USD $)	12 Months Ended
	Dec. 31, 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%

Unit-Based Compensation - Unit Option Activity (Details) (LTIP [Member], USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
LTIP [Member]
Number of Options
Outstanding at December 31, 2013 (units)	0
Granted (units)	2,500,000
Outstanding at September 30, 2014 (units)	2,500,000
Vested and Expected to vest at September 30, 2014 (units)	2,500,000
Exercisable at September 30, 2014 (units)	0
Weighted Average Exercise Price
Outstanding at December 31, 2013 (in dollars per unit)	$ 0.00
Granted (in dollars per unit)	$ 26.00
Outstanding at September 30, 2014 (in dollars per unit)	$ 26.00
Vested and Expected to vest at September 30, 2014 (in dollars per unit)	$ 26.00
Exercisable at September 30, 2014 (in dollars per unit)	$ 0.00
Outstanding at end of period, remaining term	2 years 5 months 18 days
Vested and expected to vest at end of period, remaining term	2 years 5 months 18 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

Partners' Capital and Partnership Distributions (Details)		12 Months Ended		0 Months Ended
	Dec. 31, 2014	Dec. 31, 2014 Cash Distribution [Member]	Dec. 31, 2014 Diamondback Energy, Inc. [Member] Limited Partner [Member]	Jun. 23, 2014 IPO [Member] Limited Partner [Member]	Sep. 19, 2014 Public Offering [Member] Limited Partner [Member]
Limited Partners' Capital Account [Line Items]
Common units issued	79,708,888
Common units outstanding	79,708,888
Units of partnership interest			70,450,000
Units issued in public offering				5,750,000	3,500,000
Percent of limited partnership interest			88.00%
Cash distributions, distribution period after quarter end		60 days

Earnings Per Unit (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified

3 Months Ended

6 Months Ended

12 Months Ended

Sep. 30, 2014

Dec. 31, 2013

Jun. 22, 2014

Dec. 31, 2014

Earnings Per Share [Abstract]

Net income per common unit, basic (dollars per unit)

$ 22,613

^[1]

$ 2,988

^[2]

$ 7,021

$ 22,613

$ 29,634

$ 0.29

^[1]

$ 0.29

Net income per common unit, diluted (dollars per unit)

$ 0.29

^[1]

$ 0.29

Weighted-average common units outstanding, basic

78,090

^[1]

Weighted-average common units outstanding, diluted

78,102

^[1]

78,102

[1]	Net income attributable to the period June 23, 2014 through September 30, 2014
[2]	See Note 1 for information regarding the basis of financial statement presentation.

Supplemental Information on Oil and Natural Gas Operations (Unaudited) Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Oil and natural gas interests:
Proved properties	$ 419,641	$ 287,732
Unproved properties	91,444	160,302
Total oil and natural gas interests	511,085	448,034
Less accumulated depletion		(5,199)
Net oil and natural gas interests capitalized	$ 478,285	$ 442,835

Supplemental Information on Oil and Natural Gas Operations (Unaudited) Costs Incurred in Crude Oil and Natural Gas Activities (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved properties	$ 200,309	$ 10,879
Unproved properties	247,725	46,810
Total	$ 448,034	$ 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, unless otherwise specified

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Production and ad valorem taxes

Royalty income

$ 14,987

^[1]

$ 77,767

972

(972)

^[1]

(5,377)

Depletion of Oil and Gas Properties

(5,199)

^[1]

(27,601)

Results of operations from oil, natural gas and natural gas liquids

$ 8,816

$ 44,789

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

Supplemental Information on Oil and Natural Gas Operations (Unaudited) Changes in Estimated Proved Reserves (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2013 bbl	Dec. 31, 2014 bbl
Oil [Member]
Reserve Quantities [Line Items]
Beginning of the period	0	7,218,080
Purchase of reserves in place	5,725,640	225,217
Extensions and discoveries	1,724,366	6,937,134
Revisions of previous estimates	(81,111)	(693,596)
Production	(150,815)	(856,541)
End of period	7,218,080	12,830,294
Proved Developed Reserves (Volume)	3,692,207	0
Proved Undeveloped Reserve (Volume)	3,525,873	0
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning of the period	0	1,175,123
Purchase of reserves in place	1,672,824	0
Extensions and discoveries	364,047	1,370,291
Revisions of previous estimates	(841,777)	112,368
Production	(19,971)	(144,074)
End of period	1,175,123	2,513,708
Proved Developed Reserves (Volume)	609,303	0
Proved Undeveloped Reserve (Volume)	565,820	0
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of the period	0	11,261,585
Purchase of reserves in place	7,418,633	346,123
Extensions and discoveries	2,403,261	9,831,241
Revisions of previous estimates	1,547,955	(1,795,981)
Production	(108,264)	(648,808)
End of period	11,261,585	18,994,160
Proved Developed Reserves (Volume)	6,280,409	0
Proved Undeveloped Reserve (Volume)	4,981,176	0

Net quantities of an enterprise's interests in proved developed reserves of either crude oil (including condensate and natural gas liquids), natural gas, synthetic oil and gas, or other nonrenewable natural resource that is intended to be upgraded into synthetic oil and gas as of the beginning and the end of the year. "Net" quantities of reserves include those relating to the enterprise's operating and nonoperating interests in properties. Quantities of reserves relating to royalty interests owned are included in "net" quantities if the necessary information is available to the enterprise. "Net" quantities does not include reserves relating to interests of others in properties owned by the enterprise. The unit of measure for reserve quantities is defined as "barrels" for oil and synthetic oil reserves or "cubic feet" or "cubic meters" for natural gas and synthetic gas reserves.

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