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•	the volatility of realized oil and natural gas prices and the extent and duration of price reductions and increased production by OPEC members and other oil exporting nations;

•	the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic, or any government responses to such occurrence or threat;

•	logistical challenges and the supply chain disruptions during the ongoing COVID-19 pandemic;

•	general economic, business or industry conditions;

•	conditions in the capital, financial and credit markets;

•	conditions of U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;

•	U.S. and global economic conditions and political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental policies;

•	our ability to execute our business and financial strategies;

•	the level of production on our properties;

•	regional supply and demand factors, delays or interruptions of production, and any government order, rule or regulation that may impose production limits on properties in which we have mineral and royalty interest;

•	our ability to replace our oil and natural gas reserves;

•	our ability to identify, complete and integrate acquisitions of properties or businesses;

•	competition in the oil and natural gas industry;

•	the ability of our operators to obtain capital or financing needed for development and exploration operations;

•	title defects in the properties in which we invest;

•	uncertainties with respect to identified drilling locations and estimates of reserves;

•	the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;

•	restrictions on the use of water;

•	the availability of transportation, pipeline and storage facilities;

•	the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

•	federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

•	future operating results;

•	exploration and development drilling prospects, inventories, projects and programs;

•	operating hazards faced by our operators; and

•	the ability of our operators to keep pace with technological advancements.

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Organization

Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”) on February 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian Basin and Eagle Ford Shale. Since May 10, 2018, the Partnership has been treated as a corporation for U.S. federal income tax purposes. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of the Partnership and its consolidated subsidiary, Viper Energy Partners LLC (the “Operating Company”).

As of March 31, 2020, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback had an approximate 58% limited partner interest in the Partnership. Diamondback owns and controls the General Partner.

Basis of Presentation

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 information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2019, which contains a summary of the Partnership’s significant accounting policies and other disclosures.

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.

Making accurate estimates and assumptions are particularly difficult as the oil and gas industry experiences challenges resulting from negative pricing pressure from the effects of a decline in worldwide economic conditions. The decline in worldwide economic conditions is the result of a global COVID-19 pandemic announced in March 2020, which has reduced economic activity and resulted in a significant decline in the short term demand for oil and gas production. Companies in the oil and gas industry are beginning to change near term business plans in response to changing market conditions. The aforementioned circumstances generally increases the estimation uncertainty in our accounting estimates, particularly the accounting estimates involving financial forecasts.

The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in each particular circumstance. 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, fair value estimates of commodity derivatives, and unit–based compensation.

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Accounts Receivable

Accounts receivable consist of receivables from oil and natural gas sales. The operators remit payment for production directly to the Partnership. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition can take a few months longer due to title opinion work which is required to be completed by the operator before payments are released.

The Partnership adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the rule on January 1, 2020. Accounts receivable are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Partnership when the Partnership believes collection is doubtful. The Partnership determines its allowance by considering a number of factors, including 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 expected losses. The adoption of ASU 2016-13 did not result in a material change to the Partnership’s allowance. As the adoption of ASU 2016-13 did not result in a material allowance, no cumulative-effect adjustment was made to beginning unitholders’ equity. At March 31, 2020, the Partnership recorded an allowance for doubtful accounts of $0.2 million related to royalty income receivable. The Partnership did not record an allowance for doubtful accounts at December 31, 2019.

Derivative Instruments

The Partnership is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations.

Accrued Liabilities

Accrued liabilities consist of the following:

	March 31,				December 31,
	2020				2019
	(In thousands)
Interest payable	$	13,438			$	6,718
Ad valorem taxes payable	2,329				5,632
Other	856				932
Total accrued liabilities	$	16,623			$	13,282

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Recent Accounting Pronouncements

The Partnership considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Partnership’s analysis of the effects on its financial statements:

Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”	This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.	Q1 2020	The Partnership adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”	This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2020-04, “Rate Reform (Topic 848)”	This update provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions that reference LIBOR.	Q1 2020	The Partnership adopted this update upon issuance and elected to use the optional expedient for contracts that reference LIBOR. The amendments in this update expire on December 31, 2022. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.

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.

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Royalty income from oil, natural gas and natural gas liquids sales

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 at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net any deductions for gathering and transportation.

Transaction price allocated to remaining performance obligations

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 obligations under any of the Partnership’s royalty income contracts.

Contract balances

Under the Partnership’s royalty income contracts, it would have the right to receive royalty income 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.

Prior-period performance obligations

The Partnership records revenue in the month production is 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 months ended March 31, 2020, 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.

2020 Activity

During the three months ended March 31, 2020, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests representing 4,948 gross (410 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $63.4 million, subject to post-closing adjustments and, as of March 31, 2020, had mineral and royalty interests representing 24,714 net royalty acres. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

2019 Activity

During the three months ended March 31, 2019, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests representing 627 net royalty acres for an aggregate purchase price of approximately $82.7 million and, as of March 31, 2019, had mineral and royalty interests representing 15,469 net royalty acres. The Partnership funded these acquisitions with cash on hand, a portion of the net proceeds from its February 2019 offering of common units and borrowings under the Operating Company’s revolving credit facility.

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Oil and natural gas interests include the following:

	March 31,			December 31,
	2020			2019
	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	1,345,093		$	1,316,692
Not subject to depletion	1,587,992			1,551,767
Gross oil and natural gas interests	2,933,085			2,868,459
Accumulated depletion and impairment	(351,116		)	(326,474		)
Oil and natural gas interests, net	2,581,969			2,541,985
Land	5,688			5,688
Property, net of accumulated depletion and impairment	$	2,587,657		$	2,547,673
Balance of costs not subject to depletion:
Incurred in 2020	$	54,062
Incurred in 2019	827,680
Incurred in 2018	459,094
Incurred in 2017	247,156
Total not subject to depletion	$	1,587,992

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

	March 31,				December 31,
	2020				2019
	(in thousands)
5.375 % Senior Notes due 2027	$	500,000			$	500,000
Revolving credit facility	173,500				96,500
Unamortized debt issuance costs	(2,380		)		(2,458		)
Unamortized discount costs	(7,080		)		(7,268		)
Total long-term debt	$	664,040			$	586,774

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2027 Senior Notes

 

On October 16, 2019, the Partnership completed an offering (the “Notes Offering”) of $500.0 million in aggregate principal amount of its 5.375% Senior Notes due 2027 (the “Notes”). The Partnership received net proceeds of approximately $490.0 million from the Notes Offering. The Partnership loaned the gross proceeds to the Operating Company. The Operating Company used the proceeds from the Notes Offering to pay down borrowings under its revolving credit facility.

The Notes are senior unsecured obligations of the Partnership, initially are guaranteed on a senior unsecured basis by the Operating Company and pay interest semi-annually. Neither Diamondback nor the General Partner guarantee the Notes. In the future, each of the Partnership’s restricted subsidiaries that either (1) guarantees any of its or a guarantor’s other indebtedness or (2) is a domestic restricted subsidiary and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Notes.

Intercompany Promissory Note

In connection with and upon closing of the Notes Offering, the Partnership loaned the gross proceeds from the Notes Offering to the Operating Company under the terms of that certain subordinated promissory note, dated as of October 16, 2019, by the Operating Company in favor of the Partnership (the “Intercompany Promissory Note”). The Intercompany Promissory Note requires the Operating Company to repay the underlying loan to the Partnership on the same terms and in the same amounts as the Notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. The Partnership’s right to receive payment under the Intercompany Promissory Note is contractually subordinated to the Operating Company’s guarantee of the Notes and is structurally subordinated to all of the Operating Company’s secured indebtedness (including all borrowings and other obligations under the Operating Company’s revolving credit facility) to the extent of the value of the collateral securing such indebtedness.

The Operating Company’s Revolving Credit Facility

On July 20, 2018, the Partnership, as guarantor, entered into an amended and restated credit agreement with the Operating Company, as borrower, Wells Fargo National Bank (“Wells Fargo”), as administrative agent, and the other lenders. The credit agreement, as amended to the date hereof, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on the Operating Company’s oil and natural gas reserves and other factors (the ‘‘borrowing base’’) of $775.0 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 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 March 31, 2020, the borrowing base was set at $775.0 million and the Operating Company had $173.5 million of outstanding borrowings and $601.5 million available for future borrowings under the Operating Company’s revolving credit facility. In connection with the regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent has recommended that the borrowing base be decreased to $580.0 million, which is expected to be effective mid May 2020. The decrease is subject to approval by the requisite lenders under the Operating Company’s revolving credit facility. Under the new expected borrowing base, the Operating Company would have had $406.5 million of availability for future borrowings under the revolving credit facility as of March 31, 2020.

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.

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

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $1.0 billion 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 March 31, 2020, the Operating Company was in compliance with the financial maintenance 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.

Partnership Agreement

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 months ended March 31, 2020 and 2019, the General Partner allocated $0.9 million and $0.6 million, respectively, to the Partnership.

Tax Sharing

In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. For the three months ended March 31, 2020, the Partnership did not accrue any state income tax expense. For the three months ended March 31, 2019, the Partnership accrued state income tax expense of $47,364 for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback.

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Lease Bonus

During the three months ended March 31, 2020, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $0.3 million in lease bonus payments to extend the term of one lease and $1.3 million in lease bonus payments for one new lease. During the three months ended March 31, 2019, Diamondback paid the Partnership $198 in lease bonus payments to extend the term of one lease and $3,101 in lease bonus payments for two new leases.

Surface Use

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. As of March 31, 2020, a total of 8,867,283 common units had 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 ended March 31, 2020, the Partnership incurred $0.4 million of unit–based compensation.

Phantom Units

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 three months ended March 31, 2020:

	Phantom Units			Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	95,248			$	26.87
Vested	(42,814	)		$	23.24
Unvested at March 31, 2020	52,434			$	29.83

The aggregate fair value of phantom units that vested during the three months ended March 31, 2020 was $1.0 million. As of March 31, 2020, the unrecognized compensation cost related to unvested phantom units was $1.1 million. Such cost is expected to be recognized over a weighted-average period of 1.41 years.

During the three months ended March 31, 2020, the Partnership modified certain of the phantom units to include distribution equivalent rights during the vesting period. This modification effected 21 awards and resulted in no incremental compensation costs to be recognized.

The Partnership has general partner and limited partner units. At March 31, 2020, the Partnership had a total of 67,831,342 common units issued and outstanding and 90,709,946 Class B units issued and outstanding, of which 731,500 common units and 90,709,946 Class B units were owned by Diamondback, representing approximately 58% 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

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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:

	Common Units
Balance at December 31, 2019	67,805,707
Common units vested and issued under the LTIP	25,635
Balance at March 31, 2020	67,831,342

The Partnership had a total of 90,709,946 Class B units outstanding as of March 31, 2020 and December 31, 2019, respectively.

In March 2019, the Partnership completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximately 54% of the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $340.6 million, after deducting underwriting discounts and commissions and offering expenses. The Partnership used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under the revolving credit facility and finance acquisitions during the period.

The board of directors of the General Partner has adopted a policy for the Partnership to distribute on a quarterly basis all available cash it receives from the Operating Company.

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

		Amount per Common Unit				Declaration Date		Unitholder Record Date		Payment Date
Q4 2019		$	0.45			February 7, 2020		February 21, 2020		February 28, 2020

Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter will be determined by the board of directors of the General Partner following the end of such quarter. Available cash for each quarter will generally equal Adjusted EBITDA reduced for cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors of the General Partner deems necessary or appropriate, if any.

Amendment to LLC Agreement - Tax Allocation Placeholder

On March 30, 2020, the Partnership, as managing member of the Operating Company, entered into the First Amendment to Second Amended and Restated Limited Liability Company Agreement of the Operating Company (the “Amendment”) to extend the remaining period of special allocations to Diamondback of the Operating Company’s income and gains over losses and deductions (but before depletion) from two to four years.

The net (loss) income per common unit on the consolidated statements of operations is based on the net (loss) income of the Partnership for the three months ended March 31, 2020 and 2019, since this is the amount of net (loss) income that is attributable to the Partnership’s common units.

The Partnership’s net (loss) 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' Equity and Partnership Distributions.

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

	Three Months Ended March 31,
	2020			2019
	(In thousands, except per unit amounts)
Net (loss) income attributable to the period	$	(142,169	)	$	33,779
Less: net income allocated to participating securities(1)	(20		)	(42		)
Net (loss) income attributable to common unitholders	$	(142,189	)	$	33,737
Weighted average common units outstanding:
Basic weighted average common units outstanding	67,822			55,448
Effect of dilutive securities:
Potential common units issuable	1			27
Diluted weighted average common units outstanding	67,823			55,475
Net (loss) income per common unit, basic	$	(2.10	)	$	0.61
Net (loss) income per common unit, diluted	$	(2.10	)	$	0.61

(1)	Distribution equivalent rights granted to employees are considered participating securities.

The Partnership’s effective income tax rates were 765.3% and (87.2)% for the three months ended March 31, 2020 and 2019, respectively. Total income tax expense for the three months ended March 31, 2020 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 the impact of recording a valuation allowance on the Partnership’s deferred tax assets. Total income tax benefit for the three months ended March 31, 2019 differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the revision of estimated deferred taxes recognized as a result of the Partnership’s change in tax status.

For the three months ended March 31, 2020, the Partnership recorded a discrete income tax expense of approximately $142.5 million related to application of a full valuation allowance on the Partnership’s beginning-of-the-year deferred tax assets, which consist primarily of its investment in the Operating Company and federal net operating loss carryforwards. A valuation allowance was also applied against the year-to-date tax benefit resulting from the Partnership’s projected pretax loss for the year. The determination to record a valuation allowance was based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets, as required by applicable financial accounting standards.  In light of those criteria for recognizing the tax benefit of deferred tax assets, the Partnership’s assessment resulted in recording a full valuation allowance against its deferred tax assets as of March 31, 2020.

For the three months ended March 31, 2019, the Partnership recorded a discrete income tax benefit of approximately $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 consisted primarily of the sum of the Partnership’s unitholders’ tax basis 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 was not available until unitholders’ tax basis information was fully reported and the Partnership finalized its federal income tax computations for 2018. Based on information available as of March 31, 2019, the Partnership revised its estimate of the difference between its

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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 three months ended March 31, 2019.

All derivative financial instruments are recorded at fair value. The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the combined consolidated statements of operations under the caption “Loss on derivative instruments, net.”

    

Commodity Contracts

The Partnership uses fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. With respect to the Partnership’s fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to the Partnership if the settlement price for any settlement period is less than the swap or basis price, and the Partnership is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap or basis price. The Partnership has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price.

Under the Partnership’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Partnership and when the settlement price is above the ceiling price, the Partnership is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

The Partnership’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Midland-Cushing) and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub and Waha Hub pricing.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk. The Partnership’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Partnership is not required to post any collateral. The Partnership does not require collateral from its counterparties. The Partnership has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.

As of March 31, 2020, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	2020
Swaps	Volume (Bbls/MMBtu)			Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	275,000			$	27.45
Oil Basis Swaps - WTI (Midland-Cushing)	1,100,000			$	(2.60	)
Natural Gas Basis Swaps - Waha Hub	6,875,000			$	(2.07	)

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Collars - WTI (Cushing)	2020				2021
Volume (Bbls)	3,850,000				3,650,000
Floor price (per Bbl)	$	28.86			$	30.00
Ceiling price (per Bbl)	$	32.33			$	43.05

Balance sheet offsetting of derivative assets and liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement.

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Partnership’s consolidated balance sheets as of March 31, 2020 and December 31, 2019.

	March 31, 2020			December 31, 2019
	(in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	25,105		$	—
Amounts netted in the Consolidated Balance Sheet	(24,267		)	—
Net amounts of assets presented in the Consolidated Balance Sheet	$	838		$	—
Gross amounts of liabilities presented in the Consolidated Balance Sheet	$	32,594		$	—
Amounts netted in the Consolidated Balance Sheet	(24,267		)	—
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	8,327		$	—

The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Partnership’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:

	March 31, 2020			December 31, 2019
	(in thousands)
Current assets: derivative instruments	$	776		$	—
Noncurrent assets: derivative instruments	62			—
Total assets	$	838		$	—
Current liabilities: derivative instruments	$	7,362		$	—
Noncurrent liabilities: derivative instruments	965			—
Total liabilities	$	8,327		$	—

None of the Partnership’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:

	Three Months Ended March 31,
	2020			2019
	(in thousands)
Change in fair value of open non-hedge derivative instruments	$	(7,489	)	$	—
Loss on settlement of non-hedge derivative instruments	(453		)	—
Loss on derivative instruments	$	(7,942	)	$	—

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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. The Partnership’s 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. The Partnership uses appropriate valuation techniques based on available inputs to measure the fair values of its 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 Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Partnership’s derivative instruments and cost method investment. The investment is a Level 1 classification in the fair value hierarchy. The fair values of the Partnership’s fixed price swaps, fixed price basis swaps and costless collars are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2020 and December 31, 2019:

	March 31, 2020										December 31, 2019
	Level 1			Level 2			Level 3				Level 1			Level 2			Level 3
	(in thousands)
Assets:
Investment	$	9,237		$	—		$	—			$	19,357		$	—		$	—
Derivative Instruments	—			838			—				—			—			—
Liabilities:
Derivative Instruments	$	—		$	8,327		$	—			$	—		$	—		$	—

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:

	March 31, 2020								December 31, 2019
	Carrying Value				Fair Value				Carrying Value				Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	173,500			$	173,500			$	96,500			$	96,500
5.375% Senior Notes due 2027(1)	$	490,540			$	420,150			$	490,274			$	521,100

(1) The carrying value includes associated deferred loan costs and any discount.

The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the March 31, 2020 quoted market price, a Level 1 classification in the fair value hierarchy.

The Partnership is a party to various legal proceedings, disputes and claims from time to time arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry. These proceedings, disputes and claims may include differing interpretations as to the prices at which crude oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, title claims, environmental issues and other matters. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Partnership, cannot be predicted with certainty, the Partnership believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, cash flows or results of operations. The Partnership’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Partnership’s assessment. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Cash Distribution

On April 30, 2020, the board of directors of the General Partner approved a cash distribution for the first quarter of 2020 of $0.10 per common unit, payable on May 21, 2020, to eligible unitholders of record at the close of business on May 14, 2020. This distribution represents 25% of total cash available for distribution with the remaining cash flow expected to be retained to strengthen the Partnership’s balance sheet. The board of directors of the General Partner intends to review this distribution policy quarterly.

The Partnership’s Credit Facility

In connection with the Partnership’s regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent has recommended that the Partnership’s borrowing base be decreased to $580.0 million, which is expected to be effective mid May 2020. The decrease is subject to approval by the requisite lenders under the Operating Company’s revolving credit facility. Under the new expected borrowing base, the Operating Company would have $406.5 million of availability for future borrowings under the revolving credit facility as of March 31, 2020.

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Current Commodity Environment

Oil prices dropped sharply in early March 2020 and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international performance. The Partnership cannot predict when prices will improve and stabilize.

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(1)

The average realized price of $0.13 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 first quarter of 2020, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(1.60) 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.

(2)	Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. We did not have any derivative contracts prior to February of 2020.

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(1)	Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

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