Net income attributable to common limited partners per unit:

$ 4,109

^[1]

$ 2,988

^[1]

$ 7,962

^[1]

Basic (dollars per unit)

$ 0.01

^[1]

$ 0.01

^[1]

Diluted (dollars per unit)

$ 0.01

^[1]

$ 0.01

^[1]

Weighted average number of limited partner units outstanding

Basic (in units)

76,200,000

^[1]

76,200,000

^[1]

Diluted (in units)

76,200,000

^[1]

76,200,000

^[1]

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

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

Total

Limited Partner [Member]

Members' Equity [Member]

Predecessor [Member]

Partners' capital at Sep. 17, 2013

$ 0

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

Partners' capital at Dec. 31, 2013

2,988

^[1]

2,988

^[1]

2,988

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

Partners' capital at Jun. 22, 2014

7,021

^[1]

7,021

Partners' capital at Dec. 31, 2013

^[1]

2,988

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

Contribution of Note Payable to Equity

437,115

Distribution payable to Diamondback

(11,260)

Exchange of Predecessor interests for units

435,864

(435,864)

Net proceeds from the issuance of common units

137,238

Distribution to Diamondback

(137,500)

Unit-based compensation

128

Partners' capital at Jun. 30, 2014

^[1]

7,962

436,671

Partners' capital at Jun. 22, 2014

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

Partners' capital at Jun. 30, 2014

941

^[1]

941

$ 436,671

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

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

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Cash flows from operating activities:

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

$ 2,988

^[1]

$ 7,962

^[1]

Depletion

5,199

^[1]

11,631

^[1]

Unit-based compensation expense

^[1]

128

^[1]

Changes in operating assets and liabilities:

Royalty income receivable

(9,426)

^[1]

2,258

^[1]

Other current assets

^[1]

(16)

^[1]

Accounts payable-related party

5,828

^[1]

(9,172)

^[1]

Accounts payable and other accrued liabilities

256

^[1]

1,273

^[1]

Net cash provided by operating activities

4,845

^[1]

14,064

^[1]

Cash flows from investing activities:

Additions to oil and natural gas interests

(4,083)

^[1]

(5,275)

^[1]

Net cash used in investing activities

(4,083)

^[1]

(5,275)

^[1]

Cash flows from financing activities

Principal payment on subordinated note

^[1]

(2,885)

^[1]

Proceeds from initial public offering

^[1]

139,035

^[1]

Initial public offering costs

^[1]

(1,172)

^[1]

Distribution to Diamondback

^[1]

(137,500)

^[1]

Net cash used in financing activities

^[1]

(2,522)

^[1]

Net increase in cash

762

^[1]

6,267

^[1]

Cash at beginning of period

^[1]

762

^[1]

Cash at end of period

762

^[1]

7,029

^[1]

Supplemental disclosure of cash flow information:

Interest paid, net of capitalized interest

^[1]

16,496

^[1]

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

^[1]

Capitalized interest

$ 3,951

^[1]

$ 5,275

^[1]

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

Organization and Basis of Presentation

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Accounting Policies [Abstract]

Organization and Basis of Presentation

1.	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.

The Predecessor was formed on September 18, 2013 to own and acquire mineral and other oil and natural gas interests in properties in the Permian Basin in West Texas. The assets of the Predecessor consisted of mineral interests in oil and natural gas properties in the Permian Basin, which were acquired on September 19, 2013. See Note 3—Acquisition. For the period from its inception to June 17, 2014, the Predecessor was a wholly owned subsidiary of Diamondback.

Prior to the completion on June 23, 2014 of the Partnership’s initial public offering (the “IPO”) of 5,750,000 common units representing limited partner interests, Diamondback owned all of the general and limited partner interests in the Partnership. On June 23, 2014, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms.

In connection with the IPO, on June 17, 2014, 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.

Basis of Presentation

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 and with the operations of the Partnership and the Predecessor as if they were consolidated for all periods presented. 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. Therefore, 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.

The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles that are generally accepted in the United States.

1.	ORGANIZATION AND BASIS OF PRESENTATION

Organization

Prior to the completion on June 23, 2014 of the Partnership’s initial public offering (the “IPO”) of 5,750,000 common units representing limited partner interests, Diamondback owned all of the general and limited partner interests in the Partnership. On June 23, 2014, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests at a price to the public of $26.00 per common unit, which included 750,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms. We received net proceeds of approximately $137.2 million from the sale of these common units, net of offering expenses and underwriting discounts and commissions.

In connection with the IPO, Diamondback contributed all of the membership interests in the Predecessor to the Partnership in exchange for 70,450,000 common units, and Viper Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company, maintained its non-economic general partner interest. In addition, in connection with the closing of the IPO, the Partnership agreed to distribute to Diamondback all cash and cash equivalents and the royalty income receivable on hand in the aggregate amount of approximately $11.3 million and the net proceeds from the IPO. As of June 30, 2014, the Partnership had distributed $137.5 million to Diamondback and the Partnership recorded a payable balance of approximately $11.3 million.

The contribution of the Predecessor to the Partnership was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests.

As of June 30, 2014, the General Partner held a 100% non-economic general partner interest in the Partnership, and our affiliates had an approximate 93% limited partner interest in the Partnership consisting of Diamondback holding an approximate 92% limited partner interest and Wexford Capital LP (“Wexford”) holding an approximate 1% limited partner interest. Diamondback owns and controls the General Partner.

Basis of Presentation

The consolidated results of operations following the completion of the IPO are presented together with the results of operations pertaining to our Predecessor. The assets of the Predecessor consisted of mineral interests in oil and natural gas properties in the Permian Basin, which were acquired on September 19, 2013. See Note 3—Acquisition. The contribution of the Predecessor to the Partnership on June 17, 2014 was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. The Partnership did not own any assets prior to June 17, 2014, the date of the contribution agreement by and among Diamondback, the Predecessor, the General Partner and the Partnership. Prior to the IPO, the Predecessor was a wholly owned subsidiary of Diamondback. For periods prior to June 17, 2014, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in members’ equity of the Predecessor and, for periods on and after June 17, 2014, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in partners’ equity of the Partnership and its wholly owned subsidiary.

The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles that are generally accepted in the United States. All material intercompany balances and transactions are eliminated in consolidation.

Summary of Significant Accounting Policies

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

+ References+ Details

Summary of Significant Accounting Policies

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Accounting Policies [Abstract]

2.	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 and the carrying value of oil and natural gas properties.

Accounts Receivable

Accounts 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 the Partnership. 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.

Accounts receivable are stated at amounts due from operators, net of an allowance for doubtful accounts when the Partnership believes collection is doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to the Partnership, the condition of the general economy and the industry as a whole. The Partnership writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2013.

Fair Value of Financial Instruments

The Partnership’s financial instruments consist of cash, receivables, payables and a note payable. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of the instruments. The note payable is carried at cost, which approximates fair value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities.

Oil and Natural Gas Properties

The Partnership accounts for its oil and natural gas producing activities using 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, 2013, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $27.53 for the period from inception (September 18, 2013) to December 31, 2013. Depletion for oil and gas properties was $5.2 million for the same period.

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 period from inception (September 18, 2013) through 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 period from inception (September 18, 2013) to December 31, 2013, the Partnership capitalized approximately $4.0 million of interest expense.

Royalty Interest and Revenue Recognition

Royalty interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. Revenue is recorded when title passes to the purchaser.

Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur any of the costs of exploration, development and operation of the property.

Concentrations

The Partnership is subject to risk resulting from the concentration of its royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the period from inception (September 18, 2013) to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%); and Permian Trucking (19%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Income Taxes

The Partnership and the Predecessor are organized as pass-through entities for income tax purposes. Prior to the IPO, as appropriate, the taxable income or loss applicable to operations of the Predecessor was included in the federal income tax returns of Diamondback Energy, Inc. and no income tax effect is included in the accompanying financial statements.

The Partnership is subject to the Texas margin tax. Any amounts related to the Partnership for 2013 will be included in Diamondback’s unitary filing for this tax. Diamondback does not expect any Texas margin tax to be due for 2013, so no amount has been provided in these financial statements. On a stand-alone basis, the Partnership would have owed approximately $98 for the Texas margin tax in 2013.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the financial statements.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties and unit–based compensation.

Royalty Income Receivable

Royalty income receivable consist of receivables from oil and natural gas sales delivered to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Some of our oil and natural gas properties are contractually operated by Diamondback. Most payments are received within three months after the production date.

Royalty income receivable are stated at amounts due from operators, net of an allowance for doubtful accounts when we believe collection is doubtful. Royalty income receivable outstanding longer than the contractual payment terms are considered past due. We determine any allowance by considering a number of factors, including the length of time royalty income receivable are past due, our previous loss history, the debtor’s current ability to pay its obligation to us, the condition of the general economy and the industry as a whole. We write off specific royalty income receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. We determined that an allowance was unnecessary at both June 30, 2014 and December 31, 2013.

Fair Value of Financial Instruments

Our financial instruments consist of cash, receivables, payables and a note payable. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of the instruments. The note payable is carried at cost, which approximates fair value based on borrowing rates available to us for bank loans with similar terms and maturities.

Oil and Natural Gas Properties

Oil and natural gas producing activities are accounted for in accordance with the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. At June 30, 2014 and December 31, 2013, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $27.44, $27.95 and $27.53 for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, respectively. Depletion for oil and gas properties was $6,064,000, $11,631,000 and $5,199,000 for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, respectively.

Under the full cost method of accounting, the net book value of oil and natural gas properties, may not exceed a calculated “ceiling”. The ceiling limitation is the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%. Estimated future net cash flows are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production. Any excess of the net book value of proved oil and natural gas properties over the ceiling is charged to expense. No impairment on proved oil and natural gas properties was recorded for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Capitalized Interest

We capitalize interest on expenditures made in connection with acquisitions of unproved properties that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these properties to their intended use. Capitalized interest cannot exceed gross interest expense. During the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, we capitalized approximately $2,348,000, $5,275,000 and $3,951,000, respectively, of interest expense.

Royalty Interest and Revenue Recognition

Royalty interest has no rights or obligations to explore, develop or operate the property and does not incur any of the costs of exploration, development and operation of the property.

Concentrations

We are subject to risk resulting from the concentration of our royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the six months ended June 30, 2014, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (70%); and Permian Transport & Trading (12%). For the period from inception (September 18, 2013) to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%); and Permian Transport & Trading (19%). We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Earnings Per Unit

Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.

Unit–Based Compensation

Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 8—Unit–Based Compensation.

Income Taxes

The Partnership is organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income.

We are subject to the Texas margin tax. Any amounts related to operations for 2013 or for the period in 2014 prior to the closing of the IPO on June 23, 2014 will be included in Diamondback’s unitary filing for this tax. Diamondback does not expect any Texas margin tax to be due for the six months ended June 30, 2014 or the period from inception (September 18, 2013) through December 31, 2013, so no amount has been provided in the accompanying financial statements of our Predecessor.

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

+ References+ Details

Acquisition

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Business Combinations [Abstract]

Acquisition

3.	ACQUISITION

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

3.	ACQUISITION

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

Oil and Natural Gas Interests

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

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Extractive Industries [Abstract]

4.	OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:


	December 31, 2013
Oil and natural gas interests:
Subject to depletion	$	287,732
Not subject to depletion-acquisition costs
Incurred in 2013		160,302

Total not subject to depletion		160,302

Gross oil and natural gas interests		448,034
Less accumulated depletion		(5,199	)

Oil and natural gas interests, net	$	442,835

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 inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within three to five years.

4.	OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:


	June 30, 2014			December 31, 2013
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	317,667		$	287,732
Not subject to depletion—acquisition costs
Incurred in 2014		5,275			—
Incurred in 2013		130,367			160,302

Total not subject to depletion		135,642			160,302

Gross oil and natural gas interests		453,309			448,034
Less accumulated depletion		(16,830	)		(5,199	)

Oil and natural gas interests, net	$	436,479		$	442,835

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

Debt

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Debt Disclosure [Abstract]

Debt

5.	NOTE PAYABLE

Subordinated Note

Effective September 19, 2013 the Partnership issued a subordinated note to Diamondback for the principal sum of $440 million for the royalty interest acquisition discussed in Note 3. The note bears interest at 7.625% per annum. Interest is 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 are due and payable in full on October 1, 2021. Any indebtedness evidenced by this note is subordinate in the right of payment to any indebtedness outstanding under the Diamondback revolving credit facility. As of December 31, 2013 there was $440 million outstanding under this note and the Partnership owed $9.7 million of accrued interest which is included in accounts payable-related party in the accompanying balance sheet.

DEBT

Credit Facility-Wells Fargo Bank

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo Bank, National Association, or Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period. As of July 8, 2014, the borrowing base was set at $110.0 million, and Wells Fargo was the only lender under the credit agreement, with a maximum credit amount of $55.0 million. Under the credit agreement, the commitment of the lenders is equal to the lessor of the aggregate maximum credit amounts of the lenders and the borrowing base. As of August 6, 2014, the borrowing base and the commitment were $110.0 million with Wells Fargo as the only lender under the credit agreement. The Partnership had outstanding borrowings of $68.0 million as of August 12, 2014.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Partnership that is based on the prime rate or LIBOR plus margins ranging from 0.50% for prime-based loans and 1.50% for LIBOR loans to 1.50% for prime-based loans and 2.50% for LIBOR loans, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of the Partnership and its subsidiaries.

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


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

EBITDAX will be annualized beginning with the quarter ending September 30, 2014 and ending with the quarter ended March 31, 2015

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

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

Subordinated Note

Effective September 19, 2013, the Predecessor issued a subordinated note to Diamondback for the principal sum of $440.0 million for the royalty interest acquisition discussed in Note 3. In connection with the IPO, the subordinated note was converted to equity. The note bore interest at 7.625% per annum. Interest was due and payable monthly in arrears on the first business day of each calendar month. The unpaid principal balance and all accrued interest on the note were due and payable in full on October 1, 2021. Any indebtedness evidenced by this note was subordinate in the right of payment to any indebtedness outstanding under the Diamondback revolving credit facility. Prior to the completion of the IPO, there was $437.1 million of principal and interest outstanding under this note. We owed $9.7 million of accrued interest as of December 31, 2013, which is included in accounts payable—related party in the accompanying balance sheets

Fair Value Measurements

6 Months Ended

Jun. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

6.	FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. Our assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. We use appropriate valuation techniques based on available inputs to measure the fair values of our assets and liabilities.

Level 1—Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2—Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3—Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

On July 8, 2014, we entered into a secured revolving credit agreement. See Note 5—Debt. The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.

Related Party Transactions

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References+ Details

Related Party Transactions

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

6.	RELATED PARTY TRANSACTIONS

Effective September 19, 2013 the Partnership entered into a shared services agreement with Diamondback E&P LLC, a wholly owned subsidiary of Diamondback Energy, Inc. Under this agreement, Diamondback E&P LLC, provides consulting and administrative services to the Partnership. The Partnership will incur a monthly charge for the services of $26 or other amounts that are otherwise mutually agreed to in writing between Diamondback E&P LLC and the Partnership. The term of the shared services agreement continues from the effective date on a month-to-month basis until cancelled by either party upon thirty days written notice. For the period from inception (September 18, 2013) to December 31, 2013 the Partnership incurred $87 for services under this agreement. At December 31, 2013 the Partnership owed Diamondback E&P LLC $87 and this amount is included in accounts payable-related party in the accompanying balance sheet.

At December 31, 2013, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties. These interests are subject to oil and gas leases between the Partnership as lessor and Diamondback O&G LLC as lessee and are pledged as collateral to secure the Diamondback Energy, Inc. revolving credit facility.

7.	RELATED PARTY TRANSACTIONS

Partnership agreement

In connection with the closing of the IPO, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership (the “Partnership Agreement”), dated June 23, 2014.

The Partnership Agreement requires us to reimburse the General Partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by our General Partner in connection with operating our business. The Partnership Agreement does not set a limit on the amount of expenses for which our General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates. Our General Partner is entitled to determine the expenses that are allocable to us.

Advisory Services Agreement

In connection with the closing of the IPO, the Partnership and General Partner entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides us and our General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. The Advisory Services Agreement has a term of two years commencing on June 23, 2014, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event we terminate such agreement, we are obligated to pay all amounts due through the remaining term. In addition, we have agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of our General Partner for such services as may be provided by Wexford at our request in connection with future acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to our day-to-day business or operations. We have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct.

Tax Sharing

In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement (the “Tax Sharing Agreement”) with Diamondback pursuant to which we will reimburse Diamondback for our share of state and local income and other taxes for which our results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. In such a situation, we would reimburse Diamondback for the tax we would have owed had the tax attributes not been available or used for our benefit, even though Diamondback had no cash tax expense for that period.

Shared service agreements

Effective September 19, 2013, the Predecessor entered into a shared services agreement with Diamondback E&P LLC, a wholly owned subsidiary of Diamondback Energy, Inc. This agreement was terminated in connection with the IPO. Under this agreement, Diamondback E&P LLC provided consulting and administrative services to the Predecessor. The Predecessor incurred a monthly charge for the services of $26,000. For the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, we incurred costs of $78,000, $156,000 and $87,000, respectively. At June 30, 2014 and December 31, 2013, the Partnership owed Diamondback E&P LLC $607,000 and $87,000, respectively, which amounts are included in accounts payable—related party in the accompanying balance sheets.

Disclosure Of Compensation Related Costs Sharebased 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.

+ References+ Details

Unit-Based Compensation

6 Months Ended

Jun. 30, 2014

Unit-Based Compensation

8.	UNIT–BASED COMPENSATION

On June 17, 2014, in connection with the IPO, the Board of Directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 9,144,000 common units has been reserved for issuance pursuant to the LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the Board of Directors of the General Partner or a committee thereof.

For the three months and six months ended June 30, 2014, we incurred $128,000 and $128,000, respectively of unit–based compensation.

Unit Options

In accordance with the LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the LTIP will consist of new common units of the Partnership. On June 17, 2014, we granted 2,500,000 unit options to our executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the next three anniversaries of the date of grant. In the event the fair market value per unit as of the exercise date is less than the exercise price per option unit then the vested options will automatically terminate and become null and void as of the exercise date.

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


	2014
Grant-date fair value	$	4.24
Expected volatility		36.0	%
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 six months ended June 30, 2014:


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

Outstanding at June 30, 2014		2,500,000	$	26.00		2.97	$	19,500

Vested and Expected to vest at June 30, 2014		2,500,000	$	26.00		2.97	$	19,500

Exercisable at June 30, 2014		—	$	—		—	$	—

As of June 30, 2014, the unrecognized compensation cost related to unvested unit options was $10,472,000. Such cost is expected to be recognized over a weighted-average period of 3.0 years.

Unitholders' Equity and Partnership Distributions

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

+ References+ Details

Unitholders' Equity and Partnership Distributions

6 Months Ended

Jun. 30, 2014

Equity [Abstract]

9.	UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and common unit partnership interests. The general partner interest is a non-economic interest and is not entitled to any cash distributions.

At June 30, 2014, the Partnership had a total of 76,200,000 common units issued and outstanding, of which 70,450,000 common units were owned by Diamondback, representing approximately 92% of the total Partnership units outstanding.

The board of directors of our General Partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis, beginning with the quarter ending September 30, 2014. Our first distribution, however, will include available cash for the period from June 23, 2014, the date of the close of the IPO, through September 30, 2014. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter will be determined by the board of directors of the General 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 our 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.

+ References+ Details

Earnings per Unit

6 Months Ended

Jun. 30, 2014

Earnings Per Share [Abstract]

Earnings per Unit

10.

EARNINGS PER UNIT

The net income per common unit on the consolidated statements of operations is based on the net income of the Partnership after the closing of its IPO on June 23, 2014 through June 30, 2014, since this is the amount of net income that is attributable to the Partnership’s common units.

The Partnership’s net income is allocated wholly to the common units as the General Partner does not have an economic interest.

Basic and diluted net income per common unit is calculated by dividing net income by the weighted-average number of common units outstanding during the period.


	June 23, 2014 to June 30, 2014
Net income attributable to the period June 23, 2014 through June 30, 2014	$	941,000
Net income per common unit, basic	$	0.01
Net income per common unit, diluted	$	0.01
Weighted-average common units outstanding, basic		76,200,000
Weighted-average common units outstanding, diluted		76,200,000

Commitments And Contingencies Disclosure [Abstract]

The entire disclosure for earnings per share.

+ References+ Details

Commitments and Contingencies

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Commitments and Contingencies

7.	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.

11.

COMMITMENTS AND CONTINGENCIES

We could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

The entire disclosure for commitments and contingencies.

+ References+ Details

Subsequent Events

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Subsequent Events [Abstract]

Subsequent Events

9.	SUBSEQUENT EVENTS

IPO and Subordinated Note

On June 23, 2014, the Partnership completed its IPO. See Note 1—Organization and Basis of Presentation for further information. In connection with the IPO, the subordinated note discussed in Note 5—Note Payable was converted to equity.

Credit Facility-Wells Fargo Bank

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo Bank, National Association, or Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period. As of July 8, 2014, the borrowing base was set at $110.0 million, and Wells Fargo was the only lender under the credit agreement, with a maximum credit amount of $55.0 million. Under the credit agreement, the commitment of the lenders is equal to the lessor of the aggregate maximum credit amounts of the lenders and the borrowing base. As of August 6, 2014, the borrowing base was increased to $110.0 million with Wells Fargo as the only lender under the credit agreement. The Partnership had outstanding borrowings of $50.0 million as of August 6, 2014.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Partnership that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of the Partnership and its subsidiaries.


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

EBITDAX will be annualized beginning with the quarter ending September 30, 2014 and ending with the quarter ended March 31, 2015

12.

SUBSEQUENT EVENTS

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as the administrative agent, sole book runner and lead arranger. See Note 5—Debt for further information.

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

3 Months Ended

Dec. 31, 2013

Extractive Industries [Abstract]

8.	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, 2013
Oil and natural gas interests:
Proved	$	287,732
Unproved		160,302

Total oil and natural gas interests		448,034
Less accumulated depletion		(5,199	)

Net oil and natural gas interests capitalized	$	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 (September 18, 2013) Through December 31, 2013
Acquisition costs
Proved	$	200,309
Unproved		247,725

Total	$	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 our oil, natural gas and natural gas liquids operations.


	Period From Inception (September 18, 2013) Through December 31, 2013
Royalty income	$	14,987
Production and ad valorem taxes		(972	)
Depletion		(5,199	)

Results of operations from oil, natural gas and natural gas liquids	$	8,816

Oil and Natural Gas Reserves

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


	Oil (Bbls)			Natural Gas Liquids (Bbls)			Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
Balance at inception (September 18, 2013)		—			—			—
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

Proved Developed Reserves:
December 31, 2013		3,692,207			609,303			6,280,409

Proved Undeveloped Reserves:
December 31, 2013		3,525,873			565,820			4,981,176

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.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is 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, 2013.


	December 31, 2013
Future cash inflows	$	770,528
Future production taxes		(53,040	)
Future state margin tax expenses		(5,394	)

Future net cash flows		712,094
10% discount to reflect timing of cash flows		(384,848	)

Standardized measure of discounted future net cash flows	$	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, 2013
	Unweighted Arithmetic Average First-Day-of-the-Month Prices
Oil (per Bbl)	$	92.64
Natural gas (per Mcf)	$	5.03
Natural gas liquids (per Bbl)	$	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 (September 18, 2013) Through December 31, 2013
Standardized measure of discounted future net cash flows at the beginning of the period	$	—
Purchase of minerals in place		249,831
Sales of oil and natural gas, net of production costs		(14,015	)
Extensions and discoveries		79,829
Net changes in prices and production costs		24,724
Revisions of previous quantity estimates		(19,383	)
Net changes in state margin taxes		(586	)
Accretion of discount		7,103
Net changes in timing of production and other		(257	)

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

Summary of Significant Accounting Policies (Policies)	3 Months Ended	6 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2013	Jun. 30, 2014
Accounting Policies [Abstract]
Use of Estimates	*Use of Estimates* Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts 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 and the carrying value of oil and natural gas properties.	*Use of Estimates* Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the financial statements. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties and unit–based compensation.
Royalty Income Receivable		*Royalty Income Receivable* Royalty income receivable consist of receivables from oil and natural gas sales delivered to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to us. Some of our oil and natural gas properties are contractually operated by Diamondback. Most payments are received within three months after the production date. Royalty income receivable are stated at amounts due from operators, net of an allowance for doubtful accounts when we believe collection is doubtful. Royalty income receivable outstanding longer than the contractual payment terms are considered past due. We determine any allowance by considering a number of factors, including the length of time royalty income receivable are past due, our previous loss history, the debtor’s current ability to pay its obligation to us, the condition of the general economy and the industry as a whole. We write off specific royalty income receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. We determined that an allowance was unnecessary at both June 30, 2014 and December 31, 2013.
Fair Value of Financial Instruments	*Fair Value of Financial Instruments* The Partnership’s financial instruments consist of cash, receivables, payables and a note payable. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of the instruments. The note payable is carried at cost, which approximates fair value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities.	*Fair Value of Financial Instruments* Our financial instruments consist of cash, receivables, payables and a note payable. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of the instruments. The note payable is carried at cost, which approximates fair value based on borrowing rates available to us for bank loans with similar terms and maturities.
Oil and Natural Gas Properties	*Oil and Natural Gas Properties* The Partnership accounts for its oil and natural gas producing activities using 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, 2013, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $27.53 for the period from inception (September 18, 2013) to December 31, 2013. Depletion for oil and gas properties was $5.2 million for the same period. 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 period from inception (September 18, 2013) through 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.	*Oil and Natural Gas Properties* Oil and natural gas producing activities are accounted for in accordance with the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. At June 30, 2014 and December 31, 2013, the Partnership’s oil and natural gas properties consist solely of mineral interests in oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $27.44, $27.95 and $27.53 for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, respectively. Depletion for oil and gas properties was $6,064,000, $11,631,000 and $5,199,000 for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, respectively. Under the full cost method of accounting, the net book value of oil and natural gas properties, may not exceed a calculated “ceiling”. The ceiling limitation is the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%. Estimated future net cash flows are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production. Any excess of the net book value of proved oil and natural gas properties over the ceiling is charged to expense. No impairment on proved oil and natural gas properties was recorded for the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013. Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Capitalized Interest	*Capitalized Interest* 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 period from inception (September 18, 2013) to December 31, 2013, the Partnership capitalized approximately $4.0 million of interest expense.	*Capitalized Interest* We capitalize interest on expenditures made in connection with acquisitions of unproved properties that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these properties to their intended use. Capitalized interest cannot exceed gross interest expense. During the three months and six months ended June 30, 2014 and for the period from inception (September 18, 2013) to December 31, 2013, we capitalized approximately $2,348,000, $5,275,000 and $3,951,000, respectively, of interest expense.
Royalty Interest and Revenue Recognition	*Royalty Interest 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.	*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 its royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the period from inception (September 18, 2013) to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%); and Permian Trucking (19%). The Partnership does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.	*Concentrations* We are subject to risk resulting from the concentration of our royalty interest revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the six months ended June 30, 2014, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (70%); and Permian Transport & Trading (12%). For the period from inception (September 18, 2013) to December 31, 2013, two purchasers accounted for more than 10% of royalty interest revenue: Shell Trading (59%); and Permian Transport & Trading (19%). We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Earnings Per Unit		*Earnings Per Unit* Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income by the weighted average number of outstanding common units.
Unit-Based Compensation		*Unit–Based Compensation* Unit–based compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. See Note 8—Unit–Based Compensation.
Income Taxes	*Income Taxes* The Partnership and the Predecessor are organized as pass-through entities for income tax purposes. Prior to the IPO, as appropriate, the taxable income or loss applicable to operations of the Predecessor was included in the federal income tax returns of Diamondback Energy, Inc. and no income tax effect is included in the accompanying financial statements. The Partnership is subject to the Texas margin tax. Any amounts related to the Partnership for 2013 will be included in Diamondback’s unitary filing for this tax. Diamondback does not expect any Texas margin tax to be due for 2013, so no amount has been provided in these financial statements. On a stand-alone basis, the Partnership would have owed approximately $98 for the Texas margin tax in 2013.	*Income Taxes* The Partnership is organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. We are subject to the Texas margin tax. Any amounts related to operations for 2013 or for the period in 2014 prior to the closing of the IPO on June 23, 2014 will be included in Diamondback’s unitary filing for this tax. Diamondback does not expect any Texas margin tax to be due for the six months ended June 30, 2014 or the period from inception (September 18, 2013) through December 31, 2013, so no amount has been provided in the accompanying financial statements of our Predecessor.
Accounts Receivable	*Accounts Receivable* Accounts 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 the Partnership. 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. Accounts receivable are stated at amounts due from operators, net of an allowance for doubtful accounts when the Partnership believes collection is doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to the Partnership, the condition of the general economy and the industry as a whole. The Partnership writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2013.

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

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities

Oil and natural gas interests include the following:


	December 31, 2013
Oil and natural gas interests:
Subject to depletion	$	287,732
Not subject to depletion-acquisition costs
Incurred in 2013		160,302

Total not subject to depletion		160,302

Gross oil and natural gas interests		448,034
Less accumulated depletion		(5,199	)

Oil and natural gas interests, net	$	442,835

Oil and natural gas interests include the following:


	June 30, 2014			December 31, 2013
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	317,667		$	287,732
Not subject to depletion—acquisition costs
Incurred in 2014		5,275			—
Incurred in 2013		130,367			160,302

Total not subject to depletion		135,642			160,302

Gross oil and natural gas interests		453,309			448,034
Less accumulated depletion		(16,830	)		(5,199	)

Oil and natural gas interests, net	$	436,479		$	442,835

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

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 (September 18, 2013) Through December 31, 2013
Acquisition costs
Proved	$	200,309
Unproved		247,725

Total	$	448,034

Results of Operations from Oil and Natural Gas Producing Activities


	Period From Inception (September 18, 2013) Through December 31, 2013
Royalty income	$	14,987
Production and ad valorem taxes		(972	)
Depletion		(5,199	)

Results of operations from oil, natural gas and natural gas liquids	$	8,816

Changes in Estimated Proved Reserves

The changes in estimated proved reserves are as follows:


	Oil (Bbls)			Natural Gas Liquids (Bbls)			Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
Balance at inception (September 18, 2013)		—			—			—
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

Proved Developed Reserves:
December 31, 2013		3,692,207			609,303			6,280,409

Proved Undeveloped Reserves:
December 31, 2013		3,525,873			565,820			4,981,176

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, 2013.


	December 31, 2013
Future cash inflows	$	770,528
Future production taxes		(53,040	)
Future state margin tax expenses		(5,394	)

Future net cash flows		712,094
10% discount to reflect timing of cash flows		(384,848	)

Standardized measure of discounted future net cash flows	$	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, 2013
	Unweighted Arithmetic Average First-Day-of-the-Month Prices
Oil (per Bbl)	$	92.64
Natural gas (per Mcf)	$	5.03
Natural gas liquids (per Bbl)	$	38.45

Principal Changes in the 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 (September 18, 2013) Through December 31, 2013
Standardized measure of discounted future net cash flows at the beginning of the period	$	—
Purchase of minerals in place		249,831
Sales of oil and natural gas, net of production costs		(14,015	)
Extensions and discoveries		79,829
Net changes in prices and production costs		24,724
Revisions of previous quantity estimates		(19,383	)
Net changes in state margin taxes		(586	)
Accretion of discount		7,103
Net changes in timing of production and other		(257	)

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

Aggregate [Member]

Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities

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


	December 31, 2013
Oil and natural gas interests:
Proved	$	287,732
Unproved		160,302

Total oil and natural gas interests		448,034
Less accumulated depletion		(5,199	)

Net oil and natural gas interests capitalized	$	442,835

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef

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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

Schedule of Financial Covenants

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

Debt (Tables)

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Debt Disclosure [Abstract]

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


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

Unit-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2014

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Schedule of valuation assumptions

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	%

Schedule of unit option activity

The following table presents the unit option activity under the LTIP for the six months ended June 30, 2014:


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

Outstanding at June 30, 2014		2,500,000	$	26.00		2.97	$	19,500

Vested and Expected to vest at June 30, 2014		2,500,000	$	26.00		2.97	$	19,500

Exercisable at June 30, 2014		—	$	—		—	$	—

Earnings per Unit (Tables)

6 Months Ended

Jun. 30, 2014

Earnings Per Share [Abstract]

Schedule of basic and diluted net income per common unit

Basic and diluted net income per common unit is calculated by dividing net income by the weighted-average number of common units outstanding during the period.


	June 23, 2014 to June 30, 2014
Net income attributable to the period June 23, 2014 through June 30, 2014	$	941,000
Net income per common unit, basic	$	0.01
Net income per common unit, diluted	$	0.01
Weighted-average common units outstanding, basic		76,200,000
Weighted-average common units outstanding, diluted		76,200,000

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

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 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]

Jun. 30, 2014

Affiliated Limited Partners [Member]

Limited Partner [Member]

Jun. 23, 2014

Diamondback Energy, Inc. [Member]

Jun. 23, 2014

Diamondback Energy, Inc. [Member]

Limited Partner [Member]

Jun. 30, 2014

Diamondback Energy, Inc. [Member]

Limited Partner [Member]

Jun. 30, 2014

Wexford [Member]

Limited Partner [Member]

Limited Partners' Capital Account [Line Items]

Units issued in public offering

5,750,000

750,000

Price per common unit (in dollars per unit)

$ 26.00

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

$ 137,200,000

Conversion of membership interests to common units

70,450,000

Distribution to Diamondback

137,500,000

Distribution payable

$ 11,260,000

$ 0

^[1]

$ 11,300,000

Percent of General Partner interest

100.00%

Percent of limited partnership interest

93.00%

92.00%

1.00%

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

Summary of Significant Accounting Policies - Oil and Natural Gas Properties and Capitalized Interest (Detail) (USD $)

3 Months Ended

6 Months Ended

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Accounting Policies [Abstract]

Average depletion rate per barrel equivalent unit of production

27.44

27.53

27.95

Depletion of oil and gas properties

$ 6,064,000

^[1]

$ 5,199,000

^[1]

$ 11,631,000

^[1]

Impairment of oil and gas properties

Interest costs capitalized

2,348,000

3,951,000

^[1]

5,275,000

^[1]

Texas margin tax owed

$ 98,000

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

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

Acquisition (Detail) (USD $)
In Thousands, unless otherwise specified

3 Months Ended

6 Months Ended

0 Months Ended

Dec. 31, 2013

Jun. 30, 2014

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

14,804

Acres of oil and gas property, mineral interest, net

12,687

Consideration transferred to acquire mineral interests

$ 440,000

^[1]

$ 0

^[1]

$ 440,000

Percent of royalty interest

21.40%

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

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

3 Months Ended

6 Months Ended

Dec. 31, 2013

Jun. 30, 2014

Total not subject to depletion

Subject to depletion

$ 287,732

$ 317,667

160,302

^[1]

135,642

Gross oil and natural gas interests

448,034

^[1]

453,309

Less accumulated depletion

(5,199)

^[1]

(16,830)

Oil and natural gas interests, net

442,835

^[1]

436,479

Incurred in 2014 [Member]

Total not subject to depletion

5,275

Incurred in 2013 [Member]

Total not subject to depletion

$ 160,302

$ 130,367

Minimum [Member]

Number of years until unevaluated properties are included in full cost pool

3 years

Maximum [Member]

Number of years until unevaluated properties are included in full cost pool

5 years

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

Debt - Credit Facility (Detail) (Subsequent Event [Member], Wells Fargo [Member], Revolving Credit Agreement [Member], USD $)	0 Months Ended
	Jul. 08, 2014 Redetermination	Aug. 12, 2014	Aug. 06, 2014	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	110,000,000
Maximum credit amount				55,000,000
Amount outstanding under credit facility		$ 68,000,000	$ 50,000,000
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 (Detail) (Subsequent Event [Member], Wells Fargo [Member], Revolving Credit Agreement [Member], USD $)	Jul. 08, 2014
Subsequent Event [Member] \| Wells Fargo [Member] \| Revolving Credit Agreement [Member]
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX, not greater than 4.0	4
Ratio of current assets to liabilities, not less than 1.0	1
Maximum issuance of unsecured debt	$ 250,000,000
Reduction of borrowing base	25.00%

Debt - Subordinated Note (Detail) (Diamondback Energy, Inc. [Member], Subordinated Note [Member], USD $) In Millions, unless otherwise specified	Jun. 22, 2014	Dec. 31, 2013	Sep. 19, 2013
Diamondback Energy, Inc. [Member] \| Subordinated Note [Member]
Debt Instrument [Line Items]
Principal amount			$ 440.0
Stated interest rate			7.625%
Long-term debt and interest outstanding	437.1	440.0
Accrued interest		$ 9.7

Advisory services agreement, annual fee

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).

+ References+ Details

Related Party Transactions (Detail) (USD $)

3 Months Ended

6 Months Ended

0 Months Ended

3 Months Ended

6 Months Ended

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Wexford [Member]

Advisory Services Agreement [Member]

Dec. 31, 2013

Diamondback E&P LLC [Member]

Shared Service Agreement [Member]

Jun. 30, 2014

Diamondback E&P LLC [Member]

Shared Service Agreement [Member]

Jun. 22, 2014

Diamondback E&P LLC [Member]

Predecessor [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

78,000

^[1]

87,000

^[1]

156,000

^[1]

87,000

Amounts owed to related party

$ 607,000

$ 9,779,000

^[1]

$ 607,000

$ 87,000

$ 607,000

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

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

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).

+ References+ Details

Unit-Based Compensation - Additional Disclosures (Detail) (USD $)
In Thousands, except Share data, unless otherwise specified

3 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

LTIP [Member]

Jun. 17, 2014

LTIP [Member]

Jun. 17, 2014

Executive Officers of General Partner [Member]

LTIP [Member]

Jun. 30, 2014

Unit Options [Member]

Jun. 17, 2014

Unit Options [Member]

Executive Officers of General Partner [Member]

LTIP [Member]

Common units reserved for issuance

9,144,000

Unit-based compensation expense

$ 128

$ 0

^[1]

$ 128

^[1]

Unit options granted

2,500,000

Vesting percentage for next three anniversaries

33.00%

Unrecognized compensation cost related to unvested unit options

$ 10,472

Unrecognized compensation cost related to unvested unit options, period of recognition

3 years

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

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

Unit-Based Compensation - Unit Option Activity (Detail) (LTIP [Member], USD $) In Thousands, except Share data, unless otherwise specified	6 Months Ended
	Jun. 30, 2014
LTIP [Member]
Number of Options
Outstanding at December 31, 2013 (units)	0
Granted (units)	2,500,000
Outstanding at June 30, 2014 (units)	2,500,000
Vested and Expected to vest at June 30, 2014 (units)	2,500,000
Exercisable at June 30, 2014 (units)	0
Weighted Average Exercise Price
Outstanding at December 31, 2013 (in dollars per unit)	$ 0.00
Granted (in dollars per unit)	$ 26.00
Outstanding at June 30, 2014 (in dollars per unit)	$ 26.00
Vested and Expected to vest at June 30, 2014 (in dollars per unit)	$ 26.00
Exercisable at June 30, 2014 (in dollars per unit)	$ 0.00
Outstanding at end of period, remaining term	2 years 11 months 19 days
Vested and expected to vest at end of period, remaining term	2 years 11 months 19 days
Exercisable at end of period, remaining term	0 years
Outstanding at end of period, intrinsic value	$ 19,500
Vested and expected to vest at end of period, intrinsic value	19,500
Exercisable at end of period, intrinsic value	$ 0

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

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

0 Months Ended

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 22, 2014

Jun. 30, 2014

Dec. 31, 2013

Jun. 22, 2014

Jun. 30, 2014

Earnings Per Share [Abstract]

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

$ 941

^[1]

$ 3,168

^[1]

$ 4,109

^[1]

$ 2,988

^[1]

$ 7,021

^[1]

$ 7,962

^[1]

Net income per common unit, basic

$ 0.01

^[1]

$ 0.01

^[1]

Net income per common unit, diluted

$ 0.01

^[1]

$ 0.01

^[1]

Weighted-average common units outstanding, basic

76,200,000

^[1]

76,200,000

^[1]

Weighted-average common units outstanding, diluted

76,200,000

^[1]

76,200,000

^[1]

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

Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities (Detail) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Oil and natural gas interests:
Proved	$ 317,667	$ 287,732
Unproved		160,302
Total oil and natural gas interests		448,034
Less accumulated depletion		(5,199)
Net oil and natural gas interests capitalized		$ 442,835

Costs Incurred in Oil and Natural Gas Activities (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2013
Acquisition costs
Proved	$ 200,309
Unproved	247,725
Total	$ 448,034

Results of Operation from Oil and Natural Gas Producing Activities (Detail) (USD $)
In Thousands, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Extractive Industries [Abstract]

Royalty income

$ 17,249

^[1]

$ 14,987

^[1]

$ 33,102

^[1]

Production and ad valorem taxes

(1,392)

^[1]

(972)

^[1]

(2,313)

^[1]

Depletion

(6,064)

^[1]

(5,199)

^[1]

(11,631)

^[1]

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

$ 8,816

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

Changes in Estimated Proved Reserves (Detail)	3 Months Ended
Changes in Estimated Proved Reserves (Detail)	Dec. 31, 2013 bbl
Oil [Member]
Reserve Quantities [Line Items]
Balance at inception (September 18, 2013)	0
Purchase of reserves in place	5,725,640
Extensions and discoveries	1,724,366
Revisions of previous estimates	(81,111)
Production	(150,815)
As of December 31, 2013	7,218,080
Proved Developed Reserves: December 31, 2013	3,692,207
Proved Undeveloped Reserves: December 31, 2013	3,525,873
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance at inception (September 18, 2013)	0
Purchase of reserves in place	1,672,824
Extensions and discoveries	364,047
Revisions of previous estimates	(841,777)
Production	(19,971)
As of December 31, 2013	1,175,123
Proved Developed Reserves: December 31, 2013	609,303
Proved Undeveloped Reserves: December 31, 2013	565,820
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance at inception (September 18, 2013)	0
Purchase of reserves in place	7,418,633
Extensions and discoveries	2,403,261
Revisions of previous estimates	1,547,955
Production	(108,264)
As of December 31, 2013	11,261,585
Proved Developed Reserves: December 31, 2013	6,280,409
Proved Undeveloped Reserves: December 31, 2013	4,981,176

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.

+ References+ Details