SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

VIPER ENERGY PARTNERS LP

FORM 10-Q

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Forward-looking statements may include statements about:

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”) on February 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin and Eagle Ford Shale. 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 LPthe Partnership and its consolidated subsidiary, Viper Energy Partners LLC.LLC (the “Operating Company”).

In March 2018, the Board of Directors of Viper Energy Partners GP LLC (the “General Partner”)the General Partner unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 the Partnership (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC (the “Operating Company”),the Operating Company, (iii) amended and restated its existing registration rights agreement with Diamondback and (iv) entered into an exchange agreement with Diamondback, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback delivered and assigned to the Partnership the 73,150,000 common units Diamondback owned in exchange for (i) 73,150,000 of the Partnership’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, the Partnership continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and Diamondback owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of the Partnership’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and Diamondback owned the remaining approximately 59%. The Operating Company units and the Partnership’s Class B units owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

On May 10, 2018, the change in the Partnership’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to the Partnership in respect of its general partner interest and (ii) Diamondback made a cash capital contribution of $1.0 million to the Partnership in respect of the Class B units. Diamondback, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, Diamondback also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and Diamondback continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to the Partnership’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

The accompanying consolidated financial statements and related notes thereto were prepared in conformity with GAAP. All material intercompany balances and transactions are eliminated in consolidation.

These financial statements have been prepared by the Partnership without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature.

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

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

The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and iswas accounted for under the cost method. This investment is presented on the balance sheet as other long-term assets. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. ForSee Note 12—Fair Value Measurements for additional disclosure regarding the three and nine months ended September 30, 2018,impact of the Partnership recorded a lossfair value measurement of $0.2 million and a gain of $5.2 million, respectively, which then increased the Partnership’s investment balance to $20.2 million, which is included in other assets in the accompanying consolidated balance sheets.this investment.

The Partnership uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Partnership is subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 7. The7—Related Party Transactions. In addition to the 2018 tax year, the Partnership’s 2015 through 2017 tax years, periods during which the Partnership was organized as a pass-through entity for income tax purposes, remain open to examination by tax authorities. As of SeptemberJune 30, 2018 and September 30, 2017,2019, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the ninethree and six months ended SeptemberJune 30, 2018, 2017 and 2016,2019, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will beis effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. As of SeptemberJune 30, 2018,2019, the Partnership was not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update. Therefore, theThe Partnership believes the adoption ofadopted this update willeffective January 1, 2019. It did not have ana material impact on its financial position, results of operations or liquidity.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Partnership believes the adoption ofadopted this update willeffective January 1, 2019. It did not have ana material impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update will beis effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership believes the adoption ofadopted this update willeffective January 1, 2019. It did not have ana material impact on its financial position, results of operations or liquidity. The Partnership is still evaluating the impact of this standard.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease

In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In January 2019, the Financial Accounting Standards Board issued Accounting Standards Update 2019-01, “Leases (Topic 842): Codification Improvements”. This update clarifies certain presentation and transition disclosures under Topic 842. This update is still evaluatingeffective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this standard.update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

In JuneNovember 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation -2018-19, “Codification Improvements to Nonemployee Share-Based Payment Accounting”Topic 326, Financial Instruments-Credit Losses”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exceptionclarifies that receivables arising from operating leases are not in scope of specific guidance related to the attribution of compensation cost.this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018,2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. The Partnership is still evaluating the impact of this standard.

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index.

The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser or operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue.revenue, net any deductions for gathering and transportation.

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligationobligations under any of ourthe Partnership’s royalty income contracts.

Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

The Partnership records revenue in the month production is delivered to the purchaser.delivered. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three and ninesix months ended SeptemberJune 30, 2018,2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Oil and natural gas interests include the following:

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

Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas interests. Net capitalized costs are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues,revenue including estimated expenditures (based on current costs) to be incurred in developing and producing the proved reserves, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Partnership’s oil and natural gas revenue, (b) the cost of interests not being amortized, if any, and (c) the lower of cost or market value of unproved interests included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write down is required.

On July 8, 2014, the Partnership entered into a secured revolving credit agreement as amended and restated, (the “credit facility”) with Wells Fargo, as administrative agent, certain other lenders, and the Partnership’s consolidated subsidiary, Viper Energy Partners LLC (the “Operating Company”), as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and the Partnership became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, the Partnership, Wells Fargo and the other lenders amended and restated the credit agreement to reflect the assumption by the Operating Company. The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on its oil and natural gas reserves and other factors (the “borrowing base”) of $475.0$600.0 million, subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th.November 1st. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018,Effective June 27, 2019, in connection with the Partnership’s spring 2019 redetermination, the borrowing base was set at $475.0increased from $555.0 million to $600.0 million and, as of June 30, 2019, there was $296.5$212.5 million of outstanding borrowings and $178.5$387.5 million available for future borrowings under the credit facility. In connection with the Partnership’s fall 2018 redetermination, the Partnership’s borrowing base was increased to $555.0 million effective October 26, 2018.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Operating Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternative base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of the Partnership and the Operating Company.

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:

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

As of SeptemberJune 30, 2018,2019, the Operating Company was in compliance with the financial covenants under its credit agreement. The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Partnership Agreement”), requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For the three and ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, the General Partner allocated $0.6 million and $1.8$1.2 million, respectively, to the Partnership.

In connection with the closing of the IPO, the Partnership and General Partner entered into an advisory services agreement with Wexford Capital LP (“Wexford”) dated as of June 23, 2014 (the “Advisory Services Agreement”), under which Wexford providesprovided the Partnership and the General Partner with general financial and strategic advisory services related to the Partnership’s business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement

During the three and nine months ended SeptemberJune 30, 2018,2019, Diamondback paid the Partnership $2.9 million$39,000 in lease bonus payments to extend the term of 12 leases,one lease, reflecting an average bonus of $6,412$1,800 per acre. During the threesix months ended SeptemberJune 30, 2017, Diamondback did not pay the Partnership any lease bonus payments. During the nine months ended September 30, 2017,2019, Diamondback paid the Partnership $0.1 million$39,198 in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459$1,686 per acre and $3,101 in lease bonus payments for two new leases, reflecting an average bonus of $14,766 per acre. During the three and six months ended June 30, 2018, Diamondback did not pay the Partnership any lease bonus payments.

For the three and ninesix months ended SeptemberJune 30, 2018,2019, the Partnership incurred $0.4$0.5 million and $2.2$0.9 million, respectively, of unit–based compensation.

Under the LTIP, the board of directors of the General Partner is authorized to issue phantom units to eligible employees and non-employee directors. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient to one common unit of the Partnership for each phantom unit.

The following table presents the phantom unit activity under the LTIP for the ninesix months ended SeptemberJune 30, 2018:2019:

The aggregate fair value of phantom units that vested during the ninesix months ended SeptemberJune 30, 20182019 was $2.0$1.3 million. As of SeptemberJune 30, 2018,2019, the unrecognized compensation cost related to unvested phantom units was $2.0$1.3 million. Such cost is expected to be recognized over a weighted-average period of 1.30.85 years.

The Partnership has general partner and limited partner units. At SeptemberJune 30, 2018,2019, the Partnership had a total of 51,653,95662,628,357 common units issued and outstanding and 72,418,500 Class B units issued and outstanding, of which 731,500 common units and 72,418,500 Class B units were owned by Diamondback, representing approximately 59%54% of the total Partnership’s units outstanding. The Operating Company units and the Partnership’s Class B units owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

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

In January 2017,February 2019, the Partnership completed an underwritten public offering of 9,775,00010,925,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which $120.5 million was used to repay the outstanding borrowings under the revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.

The board of directors of the General Partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis beginning withall available cash it receives from the quarter ended September 30, 2014.Operating Company.

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

The net income per common unit on the consolidated statements of operations is based on the net income of the Partnership for the three and ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, 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. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 9—Unitholders’Unitholders' Equity and Partnership Distributions.

Basic net income per common unit is calculated by dividing net income by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested common units granted under the LTIP.

For the three months ended SeptemberJune 30, 20182019 and 2017,2018, there were no common units and 1,356560 common units, respectively, and for ninesix months ended SeptemberJune 30, 20182019 and 2017,2018, there were 1,092no common units and 43,4141,234 common units, respectively, that were not included in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per common unit in future periods.

As discussed further in Note 1,1—Organization and Basis of Presentation, on March 29, 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes for the period ended SeptemberJune 30, 20182019 is based on the estimated annual effective tax rate plus discrete items.

The Partnership’s effective income tax rate was (47.1)rates were 0.4% and (127.0)% for the ninethree months ended SeptemberJune 30, 2018.2019 and 2018, respectively, and (39.50)% and (72.25)% for the six months ended June 30, 2019 and 2018, respectively. Total income tax benefit for the ninethree months ended SeptemberJune 30, 20182019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and, for the six months ended June 30, 2019, due to the revision of estimated deferred taxes recognized as a result of the Partnership’s change in tax status and net income attributable to the non-controlling interest. Total income tax benefit for the three and six months ended June 30, 2018 differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily

For the ninesix months ended SeptemberJune 30, 2018,2019, the Partnership recorded a discrete income tax benefit of approximately $72.7$35.2 million related to the revision of estimated deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s federal tax status. Under federal income tax provisions applicable to the Partnership’s change in tax status, the Partnership’s basis for federal income tax purposes in its interest in the Operating Company consists primarily of the sum of the Partnership’s unitholders’ tax bases in their interests in the Partnership on the date of the tax status change. The Partnership prepared its best estimate of the resultant tax basis in the Operating Company for purposes of the Partnership’s income tax provision for the period of the change, but information necessary for the partnership to finalize its determination is not expected to be available until unitholders’ tax basis information is fully reported and the Partnership finalizes its federal income tax computations for 2018. Based on information available, the Partnership revised its estimate of the difference between its tax basis and its basis for financial accounting purposes in the Operating Company on the date of the tax status change, resulting in deferred income tax benefit of $35.2 million included in the Partnership’s income tax provision for the six months ended June 30, 2019.

Prior to May 10, 2018, the effective date of the Partnership’s change in income tax status, the Partnership was organized as a pass-through entity for income tax purposes. As a result, the Partnership’s partners were responsible for federal income taxes on their share of the Partnership’s taxable income.

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.

In connection withSubsequent to the end of the second quarter of 2019, the Partnership entered into a definitive purchase agreement to acquire certain mineral and royalty interests from subsidiaries of Diamondback for 18.3 million of the Partnership’s fall 2018 redetermination,newly-issued Class B units, 18.3 million newly-issued units of the Operating Company and $150.0 million in cash, subject to certain adjustments (the “Pending Drop-Down”). Based on the volume weighted average sales price of Viper’s common units for the 10-trading day period ending July 26, 2019 of $30.07, the transaction is valued at $700.0 million. The mineral and royalty interests being acquired in the Pending Drop-Down represent approximately 5,090 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by Diamondback, and have an average net royalty interest of approximately 3.2%. After giving pro forma effect to the Pending Drop-Down, the Partnership’s mineral interests at June 30, 2019 would have totaled 20,960 net royalty acres. The Partnership anticipates closing the Pending Drop-Down during the fourth quarter of 2019. However, the Pending Drop-Down remains subject to completion of due diligence and satisfaction of other closing conditions. There can be no assurance that the Partnership will complete the Pending Drop-Down on the terms contemplated in this report or at all. The Partnership intends to finance the cash portion of the purchase price of the Pending Drop-Down through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility.

We are a publicly traded Delaware limited partnership formed by Diamondback on February 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership isWe are currently focused on oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. As of SeptemberJune 30, 2018,2019, our general partner had a 100% general partner interest in us, and Diamondback owned 731,500 common units and all of our 72,418,500 outstanding Class B units, representing approximately 59%54% of our total units outstanding. Following the completion of the Pending Drop-Down described in this report, Diamondback will own 731,500 common units and 90,709,946 Class B units, which will represent approximately 60% of our total units outstanding. See “Pending Drop-Down and Anticipated Increase in the Borrowing Base under the Operating Company’s Revolving Credit Facility” below. Diamondback also owns and controls our general partner.

We operate in one reportable segment engaged in the acquisition of oil and natural gas properties. Our assets consist primarily of producing oil and natural gas interests principally located in the Permian Basin of West Texas.

Our income is primarily derived from royalty payments we receive from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. Royalty payments may vary significantly from period to period as a result of commodity prices, production mix and volumes of production sold by our operators.

The following table presents the breakdown of our operating income for the following periods:

As a result, our income is more sensitive to fluctuations in oil prices than is it to fluctuations in natural gas liquids or natural gas prices. Our income may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile.

During 2017,2018, NYMEX - West Texas Intermediate postedFutures Contract 1 prices ranged from $42.48$42.53 to $60.46$76.41 per Bbl and the Henry Hub spot market price of natural gasNYMEX Natural Gas Futures Contract 1 prices ranged from $2.44$2.55 to $3.71$4.84 per MMBtu. During the first ninesix months of 2018,2019, NYMEX - West Texas Intermediate postedFutures Contract 1 prices ranged from $59.20$46.54 to $77.41$66.30 per Bbl and the Henry Hub spot market price of natural gasNYMEX Natural Gas Futures Contract 1 prices ranged from $2.49$2.19 to $6.24$3.59 per MMBtu. On SeptemberJune 28, 2018,2019, the NYMEX - West Texas Intermediate posted priceFutures Contract 1 prices for crude oil was $73.16$58.47 per Bbl and the Henry Hub spot marketNYMEX Natural Gas Futures Contract 1 price of natural gas was $3.01$2.31 per MMBtu. Lower prices may not only decrease our income, but also potentially the amount of oil and natural gas that our operators can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under the credit agreement, which may be redetermined at the discretion of our lenders.

During the ninesix months ended SeptemberJune 30, 2018,2019, we acquired from unrelated third parties 2,6511,028 net royalty acres in 74 acquisitions for an aggregate purchase price of $521.2$126.9 million, subject to post-closing adjustments, bringing our total mineral interests to 13,90815,870 net royalty acres as of SeptemberJune 30, 2018.2019. We funded our acquisitions during the second quarter of 2019 with cash on hand, a portion of the net proceeds from our February 2019 equity offering and borrowings under our revolving credit facility.

Our average daily production during the thirdsecond quarter of 20182019 was 18,38419,597 BOE/d (69%(67% oil), and our operators received an average of $54.51$54.81 per Bbl of oil, $27.05$18.33 per Bbl of natural gas liquids and $2.42$(0.65) per Mcf of natural gas, for an average realized price of $43.98$39.50 per BOE. The average realized price of $(0.65) per Mcf of natural gas was primarily due to the pricing terms under our operators’ natural gas delivery contracts, which are generally tied to NYMEX price quoted at Henry Hub. Actual volumetric prices realized from the sale of natural gas, however, differ from the quoted NYMEX price as a result of quality and location differentials. During the second quarter, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(1.68) relative to the NYMEX price quoted at Henry Hub. Our operators may have varying terms under which they sell their natural gas, but we are mostly impacted by location differences resulting from supply and demand imbalances and limited takeaway capacity within the Permian Basin.

During the thirdsecond quarter of 2018, the operators of our Spanish Trail mineral interests brought online eight2019, we estimate that 198 gross (4.1 net 100% royalty interest) horizontal wells with an average royalty interest of 21.9%2.1% were turned to production on our existing acreage position with an average lateral length of 8,849 feet. Of these 198 gross wells, Diamondback is the operator of 54 with an average royalty interest of 2.8%, consistingand the remaining 144 gross wells, which have an average royalty interest of six Middle Spraberry, two Lower Spraberry, two Wolfcamp A and two Wolfcamp B wells. As1.8%, are operated by third parties. Additionally, during the second quarter of September 30, 2018, there were 172019, we acquired 401 net royalty acres for an aggregate purchase price of approximately $44.2 million, which added a further 18 gross (0.2 net 100% royalty interest) producing horizontal wells with an average royalty interest of 19.8% in various stages1.3%. In total, as of drilling or completion on this acreage. Additionally, there is active development activity on our mineral acreage outside of Spanish Trail in Loving, Reeves, Midland, Pecos, Ward, Martin, Howard and Glasscock counties. As of SeptemberJune 30, 2018,2019, we had 1,1011,212 vertical wells and 2,1832,889 horizontal wells producing on our acreage. AsThere continues to be active development on our mineral acreage as represented by approximately 377 gross horizontal wells currently in the process of October 22, 2018, there were 24active development, in which we expect to own an average 2.2% net royalty interest (8.4 net 100% royalty interest). These wells currently in the process of active development include various wells currently being drilled by the 55 active rigs which were on our acreage and 523as of July 9, 2019, in addition to other wells currently waiting to be completed, actively in the process of being completed or waiting to be turned to production. Additionally, 385 active drilling permits have been filed on our acreage in the past six months.months, in which we expect to own an average 2.2% net royalty interest (8.3 net 100% royalty interest). In July 2019, Diamondback has already turned to production ten wells in Spanish Trail in which we have an average royalty interest of 22%, which should drive strong organic growth in the second half of the year. An additional five wells in Spanish Trail are expected to be brought online in the fourth quarter of 2019, in each of which we have a 25% net royalty interest.

We declared a cash dividend for the thirdsecond quarter of 20182019 of $0.58$0.47 per common unit, payable on November 19, 2018,August 21, 2019, to unitholders of record at the close of business on November 12, 2018.August 14, 2019.

In March 2018, we announced that the Board of Directors of our general partner unanimously approved a change of our federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 we (i) amended and restated our First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, or Operating Company, (iii) amended and restated our existing registration rights agreement with Diamondback and (iv) entered into an exchange agreement with Diamondback, our general partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback delivered and assigned to us the 73,150,000 common units Diamondback owned in exchange for (i) 73,150,000 of our newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018, or Recapitalization Agreement. Immediately following that exchange, we continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and Diamondback owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of our July 2018 offering of units, we owned approximately 41% of the outstanding units issued by the Operating Company and Diamondback owned the remaining approximately 59%. The Operating Company units and our Class B units owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

On May 10, 2018, the change in our income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to us in respect of its general partner interest and (ii) Diamondback made a cash capital contribution of $1.0 million to us in respect of the Class B units. Diamondback, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, Diamondback also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 of our common units and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of our Class B units. The General Partner continues to serve as our general partner and Diamondback continues to control us. After the effectiveness of the tax status election and the completion of related transactions, our minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to our business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to our Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and our Current Report on Form 8-K filed with the SEC on May 15, 2018.

Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas interests.

In connection with the closing of the IPO, our general partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated as of June 23, 2014. The partnership agreement requires us to reimburse our 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.

Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved interests and major development projects for which proved reserves cannot yet be assigned, less accumulated depletion.

Prior to our change in federal income tax status, we were organized as a pass-through entity for income tax purposes. As a result, our partners were responsible for federal income taxes on their share of our taxable income. Subsequent to the Partnership’s change in tax status, we are subject to federal income taxes at the U.S. corporate statutory rate. The Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items.

We are subject to the Texas margin tax. For the ninethree months ended SeptemberJune 30, 2019 and 2018, we accrued less than $0.1 million and 2017,$0.2 million, respectively, and for the Partnershipsix months ended June 30, 2019 and 2018, we accrued $0.1 million and $0,$0.2 million, respectively, for Texas margin tax payable pursuant to our tax sharing agreement with Diamondback.

The following table summarizes our revenue and expenses and production data for the periods indicated.indicated: