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VNOM Viper Energy Partners

Filed: 5 May 21, 4:06pm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2021
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-36505
 
Viper Energy Partners LP
(Exact Name of Registrant As Specified in Its Charter)
DE46-5001985
(State or Other Jurisdiction of Incorporation or Organization)(I.R.S. Employer Identification Number)
500 West Texas
Suite 1200
Midland,TX79701
(Address of principal executive offices)(Zip code)
(432) 221-7400
(Registrant's telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsVNOMThe Nasdaq Stock Market LLC
(NASDAQ Global Select Market)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One):
Large Accelerated FilerAccelerated Filer
Non-Accelerated FilerSmaller Reporting Company
Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes       No   

As of April 30, 2021, the registrant had outstanding 64,707,040 common units representing limited partner interests and 90,709,946 Class B units representing limited partner interests.


VIPER ENERGY PARTNERS LP
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2021
TABLE OF CONTENTS


i

GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and natural gas terms that are used in this Quarterly Report on Form 10-Q (this “report”):
BasinA large depression on the earth’s surface in which sediments accumulate.
Bbl or barrelOne stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOOne barrel of oil.
BO/dBO per day.
BOEOne barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/dBOE per day.
British Thermal Unit or BtuThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CondensateLiquid hydrocarbons associated with the production of a primarily natural gas reserve.
Crude oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Horizontal wellsWells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBblsThousand barrels of crude oil or other liquid hydrocarbons.
MBOEOne thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
McfOne thousand cubic feet of natural gas.
Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtuOne million British Thermal Units.
Net royalty acresGross acreage multiplied by the average royalty interest.
Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.
OperatorThe individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
ProspectA specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reservesThe estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
ReservesThe estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
ReservoirA porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interestAn interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
SpudCommencement of actual drilling operations.
WTIWest Texas Intermediate.
ii

GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report:
ASUAccounting Standards Update.
DiamondbackDiamondback Energy, Inc., a Delaware corporation.
Exchange ActThe Securities Exchange Act of 1934, as amended.
GAAPAccounting principles generally accepted in the United States.
General PartnerViper Energy Partners GP LLC, a Delaware limited liability company, and the General Partner of the Partnership.
LIBORThe London interbank offered rate.
LTIPViper Energy Partners LP Long Term Incentive Plan.
NYMEXNew York Mercantile Exchange.
OPECOrganization of the Petroleum Exporting Countries.
Operating CompanyViper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy Partners LP.
PartnershipViper Energy Partners LP, a Delaware limited partnership.
SECUnited States Securities and Exchange Commission.
The NotesThe $500.0 million in aggregate principal amount of 5.375% Senior Notes due 2027 issued on October 16, 2019.

iii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report are “forward-looking statements” as defined by the SEC. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report, including those detailed under “Part II. Item 1A. Risk Factors” in this report, our Annual Report on Form 10-K for the year ended December 31, 2020 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements. 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 the Operating Company.

Forward-looking statements may include statements about:
the amounts or volatility of realized oil and natural gas prices;
the implications and logistical challenges of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic on the oil and natural gas industry, including the impact on pricing and demand for oil and natural gas and the supply chain disruptions during the ongoing COVID-19 pandemic;
changes in general economic, business or industry conditions, including conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, environmental, monetary and trade policies;
conditions in the capital, financial and credit markets and our ability to obtain capital on favorable terms or at all;
our ability to execute our business and financial strategies;
the level of production on our properties;
the impact of reduced drilling activity on our exploration and development drilling prospects, inventories, projects and programs;
regional supply and demand factors, delays, curtailments 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;
actions taken by third party operators on our mineral and royalty acreage;
our ability to replace our oil and natural gas reserves;
our ability to identify, complete and effectively 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;
uncertainties with respect to identified drilling locations and estimates of reserves;
the impact of extreme weather conditions, including the recent severe winter storms in the Permian Basin, on production volumes on our mineral and royalty acreage;
the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
future operating results;
future distributions to eligible unitholders;
impact of potential impairment charges;
the effects of future litigation; and
certain other factors discussed elsewhere in this report.

iv

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.
v

PART I. FINANCIAL INFORMATION


ITEM 1.     CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Viper Energy Partners LP
Condensed Consolidated Balance Sheets
(Unaudited)
March 31,December 31,
20212020
(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents$11,727 $19,121 
Royalty income receivable (net of allowance for credit losses)41,791 32,210 
Royalty income receivable—related party5,521 1,998 
Other current assets505 665 
Total current assets59,544 53,994 
Property:
Oil and natural gas interests, full cost method of accounting ($1,347,832 and $1,364,906 excluded from depletion at March 31, 2021 and December 31, 2020, respectively)2,895,616 2,895,542 
Land5,688 5,688 
Accumulated depletion and impairment(521,062)(496,176)
Property, net2,380,242 2,405,054 
Other assets2,018 2,327 
Total assets$2,441,804 $2,461,375 
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable$21 $43 
Accrued liabilities19,679 18,262 
Derivative instruments43,155 26,593 
Total current liabilities62,855 44,898 
Long-term debt, net528,911 555,644 
Total liabilities591,766 600,542 
Commitments and contingencies (Note 12)00
Unitholders’ equity:
General partner789 809 
Common units (64,949,540 units issued and outstanding as of March 31, 2021 and 65,817,281 units issued and outstanding as of December 31, 2020)611,172 633,415 
Class B units (90,709,946 units issued and outstanding as of March 31, 2021 and December 31, 2020)1,006 1,031 
Total Viper Energy Partners LP unitholders’ equity612,967 635,255 
Non-controlling interest1,237,071 1,225,578 
Total equity1,850,038 1,860,833 
Total liabilities and unitholders’ equity$2,441,804 $2,461,375 







See accompanying notes to condensed consolidated financial statements.
1

Viper Energy Partners LP
Condensed Consolidated Statements of Operations
(Unaudited)
Three Months Ended March 31,
20212020
(In thousands, except per unit amounts)
Operating income:
Royalty income$96,512 $76,829 
Lease bonus income325 1,622 
Other operating income139 241 
Total operating income96,976 78,692 
Costs and expenses:
Production and ad valorem taxes6,649 6,147 
Depletion24,886 24,642 
General and administrative expenses2,221 2,666 
Total costs and expenses33,756 33,455 
Income (loss) from operations63,220 45,237 
Other income (expense):
Interest expense, net(7,860)(8,963)
Gain (loss) on derivative instruments, net(31,504)(7,942)
Gain (loss) on revaluation of investment(10,120)
Other income, net38 404 
Total other expense, net(39,326)(26,621)
Income (loss) before income taxes23,894 18,616 
Provision for (benefit from) income taxes35 142,466 
Net income (loss)23,859 (123,850)
Net income (loss) attributable to non-controlling interest26,879 18,319 
Net income (loss) attributable to Viper Energy Partners LP$(3,020)$(142,169)
Net income (loss) attributable to common limited partner units:
Basic$(0.05)$(2.10)
Diluted$(0.05)$(2.10)
Weighted average number of common limited partner units outstanding:
Basic65,360 67,822 
Diluted65,360 67,823 















See accompanying notes to condensed consolidated financial statements.
2

Viper Energy Partners LP
Condensed Consolidated Statements of Changes to Unitholders' Equity
(Unaudited)

Limited PartnersGeneral PartnerNon-Controlling Interest
CommonClass BAmountAmount
UnitsAmountUnitsAmountTotal
(In thousands)
Balance at December 31, 202065,817 $633,415 90,710 $1,031 $809 $1,225,578 $1,860,833 
Unit-based compensation— 315 — — — — 315 
Issuance of common units— — — — — — 
Distribution equivalent rights payments— (24)— — — — (24)
Distributions to public— (9,036)— — — — (9,036)
Distributions to Diamondback— (102)— (25)— (12,699)(12,826)
Distributions to General Partner— — — — (20)— (20)
Change in ownership of consolidated subsidiaries, net— 2,687 — — (2,687)
Cash paid for tax withholding on vested common units— (20)— — — — (20)
Repurchased units as part of unit buyback(870)(13,043)— — — — (13,043)
Net income (loss)— (3,020)— — — 26,879 23,859 
Balance at March 31, 202164,950 $611,172 90,710 $1,006 $789 $1,237,071 $1,850,038 

Limited PartnersGeneral PartnerNon-Controlling Interest
CommonClass BAmountAmount
UnitsAmountUnitsAmountTotal
(In thousands)
Balance at December 31, 201967,806 $929,116 90,710 $1,130 $889 $1,254,285 $2,185,420 
Unit-based compensation— 387 — — — — 387 
Issuance of common units25 — — — — — — 
Distribution equivalent rights payments— (20)— — — — (20)
Distributions to public— (30,194)— — — — (30,194)
Distributions to Diamondback— (329)— (25)— (40,819)(41,173)
Distributions to General Partner— — — — (20)— (20)
Cash paid for tax withholding on vested common units— (383)— — — — (383)
Net income (loss)— (142,169)— — — 18,319 (123,850)
Balance at March 31, 202067,831 $756,408 $90,710 $1,105 $869 $1,231,785 $1,990,167 








See accompanying notes to condensed consolidated financial statements.
3

Viper Energy Partners LP
Condensed Consolidated Statements of Cash Flows
(Unaudited)

Three Months Ended March 31,
20212020
(In thousands)
Cash flows from operating activities:
Net income (loss)$23,859 $(123,850)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income taxes expense (benefit)142,466 
Depletion24,886 24,642 
(Gain) loss on derivative instruments, net31,504 7,942 
Net cash payments on derivatives(14,942)(453)
(Gain) loss on revaluation of investment10,120 
Other901 961 
Changes in operating assets and liabilities:
Royalty income receivable(9,581)20,129 
Royalty income receivable—related party(3,523)10,576 
Accounts payable and accrued liabilities1,395 3,665 
Other160 (87)
Net cash provided by (used in) operating activities54,659 96,111 
Cash flows from investing activities:
Acquisitions of oil and natural gas interests(74)(64,626)
Net cash provided by (used in) investing activities(74)(64,626)
Cash flows from financing activities:
Proceeds from borrowings under credit facility92,000 
Repayment on credit facility(27,000)(15,000)
Repurchased units as part of unit buyback(13,043)
Distributions to public(9,060)(30,214)
Distributions to Diamondback(12,826)(41,173)
Other(50)(429)
Net cash provided by (used in) financing activities(61,979)5,184 
Net increase (decrease) in cash(7,394)36,669 
Cash and cash equivalents at beginning of period19,121 3,602 
Cash and cash equivalents at end of period$11,727 $40,271 
















See accompanying notes to condensed consolidated financial statements.
4

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements
(Unaudited)


1.    ORGANIZATION AND BASIS OF PRESENTATION

Organization

Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin.

As of March 31, 2021, Viper Energy Partners GP LLC (the “General Partner”) held a 100% general partner interest in the Partnership and Diamondback Energy, Inc. (“Diamondback”) beneficially owned an approximate 59% of the Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner.

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes thereto were prepared in accordance with GAAP. All material intercompany balances and transactions have been eliminated upon consolidation. We report our operations in 1 reportable segment.

These condensed consolidated 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 SEC rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This report should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2020, which contains a summary of the Partnership’s significant accounting policies and other disclosures.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, unitholders’ equity, results of operations or cash flows.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, in 2020, the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressure in the first half of 2020, followed by a recovery in pricing in the second half of 2020 and into 2021. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those 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
5

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


interests, the recoverability of costs of unevaluated properties, the fair value determination of assets and liabilities, fair value estimates of commodity derivatives and estimates of income taxes.

Accrued Liabilities

Accrued liabilities consist of the following:
March 31,December 31,
20212020
(In thousands)
Interest payable$10,766 $4,311 
Ad valorem taxes payable1,825 6,501 
Derivatives instruments payable6,842 7,392 
Other246 58 
Total accrued liabilities$19,679 $18,262 

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In December 2019, the FASB issued 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 and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity.

The Partnership considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed.

3.    REVENUE FROM CONTRACTS WITH CUSTOMERS

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 at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

The following table disaggregates the Partnership’s total royalty income by product type:

Three Months Ended March 31,
20212020
(In thousands)
Oil income$78,344 $72,200 
Natural gas income9,044 344 
Natural gas liquids income9,124 4,285 
Total royalty income$96,512 $76,829 

4.    ACQUISITIONS

2021 Activity

The Partnership had no significant acquisition or divestiture activity during the three months ended March 31, 2021.

6

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


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, including post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

5.    OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:
March 31,December 31,
20212020
(In thousands)
Oil and natural gas interests:
Subject to depletion$1,547,784 $1,530,636 
Not subject to depletion1,347,832 1,364,906 
Gross oil and natural gas interests2,895,616 2,895,542 
Accumulated depletion and impairment(521,062)(496,176)
Oil and natural gas interests, net2,374,554 2,399,366 
Land5,688 5,688 
Property, net of accumulated depletion and impairment$2,380,242 $2,405,054 

As of March 31, 2021 and December 31, 2020, the Partnership had mineral and royalty interests representing 24,350 net royalty acres.

NaN impairment expense was recorded for the quarters ended March 31, 2021 and 2020 based on the results of the respective quarterly ceiling tests. In addition to commodity prices, the Partnership’s production rates, levels of proved reserves, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If the trailing 12-month commodity prices decline as compared to the commodity prices used in prior quarters, the Partnership will have write-downs in subsequent quarters, which may be material.

6.    DEBT

Long-term debt consisted of the following as of the dates indicated:
March 31,December 31,
20212020
(In thousands)
5.375% senior notes due 2027$479,938 $479,938 
Revolving credit facility57,000 84,000 
Unamortized debt issuance costs(1,982)(2,058)
Unamortized discount(6,045)(6,236)
Total long-term debt$528,911 $555,644 

2027 Senior Notes
 
The Partnership’s 5.375% senior notes due 2027 (the “Notes”) of $479.9 million in aggregate principal amount are senior unsecured obligations of the Partnership, are initially 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. The Notes will mature on November 1, 2027.

7

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


The Operating Company’s Revolving Credit Facility

The Operating Company’s credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base of $580.0 million based on the Operating Company’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November. As of March 31, 2021, there was $57.0 million of outstanding borrowings and $523.0 million available for future borrowings under the Operating Company’s revolving credit facility. During the three months ended March 31, 2021 and 2020, the weighted average interest rate on the Operating Company’s revolving credit facility was 1.88% and 3.32%, respectively. The revolving credit facility will mature on November 1, 2022.

As of March 31, 2021, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement.

7.    UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has general partner and limited partner units. At March 31, 2021, the Partnership had a total of 64,949,540 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 beneficially owned by Diamondback, representing approximately 59% of the Partnership’s total units outstanding. Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 58% non-controlling ownership interest in the Operating Company. The Operating Company units and the Partnership’s Class B units beneficially 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).
Implementation of Common Unit Repurchase Program

On November 6, 2020, the board of directors of the General Partner approved an expansion of the Partnership’s return of capital program with the implementation of a common unit repurchase program to acquire up to $100.0 million of the Partnership’s outstanding common units. During the three months ended March 31, 2021, the Partnership repurchased approximately $13.0 million of common units under the repurchase program. As of March 31, 2021, $62.9 million remains available for use under the repurchase program. The common unit repurchase program is authorized to extend through December 31, 2021 and the Partnership intends to purchase common units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. The repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of the Partnership’s general partner at any time.

Cash Distributions on Common Units

The board of directors of the General Partner has established a distribution policy whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to its unitholders (including Diamondback and the Partnership). The Partnership in turn distributes all of the available cash it receives from the Operating Company to its common unitholders. The Partnership’s available cash and the available cash of the Operating Company for each quarter is determined by the board of directors of the General Partner following the end of such quarter. The Operating Company’s available cash generally equals its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations, fixed charges and reserves for future operating or capital needs that the board of directors of the General Partner deems necessary or appropriate, if any. The Partnership’s available cash for each quarter generally equals the Partnership’s proportional share of the Operating Company’s available cash for the quarter, less cash needed for the payment of income taxes, if any, and the preferred distribution. The percentage of available cash distributed pursuant to the distribution policy discussed above may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet while also expanding the return of capital program through the Partnership’s common unit repurchase program. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other basis.


8

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


The following table presents information regarding cash distributions approved by the board of directors of the General Partner for the period presented:
Distributions
(In thousands)
PeriodAmount per UnitOperating Company Distributions to Diamondback
Common Unitholders(1)
Declaration DateUnitholder Record DatePayment Date
Q4 2020$0.14 $12,699 $9,162 February 19, 2021March 4, 2021March 11, 2021
(1)Includes $0.1 million paid to Diamondback.

Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter.

Change in Ownership of Consolidated Subsidiaries

Non-controlling interest in the accompanying condensed consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. Diamondback’s relative ownership interest in the Operating Company can change due to the Partnership’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on the Partnership’s units. These changes in ownership percentage and the disproportionate allocation of net income to Diamondback discussed below result in adjustments to non-controlling interest and common unitholder equity, tax effected. The following table summarizes the changes in common unitholder equity due to changes in ownership interest during the period:

Three Months Ended March 31, 2021
(In thousands)
Net income (loss) attributable to the Partnership$(3,020)
Change in ownership of consolidated subsidiaries2,687 
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest$(333)

There were 0 changes in ownership of consolidated subsidiaries during the three months ended March 31, 2020.

Allocation of Net Income

The Partnership, as managing member of the Operating Company, has entered into an agreement whereby special allocations of the Operating Company’s income and gains over losses and deductions (but before depletion) are to be made to Diamondback through 2023. These special income allocations will reduce the taxable income allocated to the Partnership’s common unitholders.

8.    EARNINGS PER COMMON UNIT

The net income (loss) per common unit on the condensed consolidated statements of operations is based on the net income (loss) of the Partnership for the three months ended March 31, 2021 and 2020, which is the amount of net income (loss) attributable to the Partnership’s common units.

The Partnership’s net income (loss) is allocated wholly to the common units, as the General Partner does not have an economic interest. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 7—Unitholders' Equity and Partnership Distributions.

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

9

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below:
Three Months Ended March 31,
20212020
(In thousands, except per unit amounts)
Net income (loss) attributable to the period$(3,020)$(142,169)
Less: net gain (loss) allocated to participating securities(1)
(24)(20)
Net income (loss) attributable to common unitholders$(3,044)$(142,189)
Weighted average common units outstanding:
Basic weighted average common units outstanding65,360 67,822 
Effect of dilutive securities:
Potential common units issuable(2)
Diluted weighted average common units outstanding65,360 67,823 
Net income (loss) per common unit, basic$(0.05)$(2.10)
Net income (loss) per common unit, diluted$(0.05)$(2.10)
(1)    Distribution equivalent rights granted to employees are considered participating securities.
(2) For the three months ended March 31, 2021, 112,436 potential common units were excluded from the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive as a result of recording a net loss attributable to the common unitholders for the period.

9.    INCOME TAXES

The Partnership’s effective income tax rate was 0.1% for the three months ended March 31, 2021, and 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 maintaining a valuation allowance on the Partnership’s deferred tax assets as discussed further below.

For the three months ended March 31, 2021, the Partnership’s total income tax provision includes current and deferred tax expense as well as a deferred tax benefit resulting from a reduction to the valuation allowance due to pre-tax income for the period. As required by applicable financial accounting standards, the reduction in the valuation allowance was based on the Partnership’s assessment of all available evidence, both positive and negative, supporting realizability of its deferred tax assets.  In light of those criteria for recognizing the tax benefit of deferred tax assets, the Partnership maintained a valuation allowance against its remaining deferred tax assets as of March 31, 2021.

The Partnership’s effective income tax rate exceeded 100% for the three months ended March 31, 2020. 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 during the first quarter of 2020.

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 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 valuation allowance against its deferred tax assets as of March 31, 2020.

The American Rescue Plan Act was enacted on March 11, 2021, and the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020, which included a number of provisions applicable to U.S. income taxes for corporations. The Partnership has considered the impact of this legislation in the period of enactment and concluded there was not a material impact to the Partnership’s current or deferred income tax balances.

10

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


10.    DERIVATIVES

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 condensed consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”
        
Commodity Contracts

The Partnership historically has used 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. 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).

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 all participants in the 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’s counterparties have been determined to have an acceptable credit risk; therefore, the Partnership does not require collateral from its counterparties.

As of March 31, 2021, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
SwapsCollarsCalls
Settlement MonthSettlement YearType of ContractBbls/Mcf Per DayIndexWeighted Average DifferentialWeighted Average Fixed PriceWeighted Average Floor PriceWeighted Average Ceiling PriceStrike Price
OIL
Apr. - Dec.2021Collars10,000WTI Cushing$—$—$30.00$43.05$—

Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of derivative instruments 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, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 11—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments included in the condensed consolidated statements of operations:
Three Months Ended March 31,
20212020
(In thousands)
Gain (loss) on derivative instruments$(31,504)$(7,942)
Net cash payments on derivatives$(14,942)$(453)
11

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


11.    FAIR VALUE MEASUREMENTS

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

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. 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. The fair values of the Partnership’s derivative contracts 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 (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Partnership’s condensed consolidated balance sheets as of March 31, 2021 and December 31, 2020. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

As of March 31, 2021
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In thousands)
Assets:
Current:
Derivative instruments$$542 $$542 $(542)$
Liabilities:
Current:
Derivative instruments$$43,697 $$43,697 $(542)$43,155 

12

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


As of December 31, 2020
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In thousands)
Assets:
Current:
Derivative instruments$$2,340 $$2,340 $(2,340)$
Liabilities:
Current:
Derivative instruments$$28,933 $$28,933 $(2,340)$26,593 

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 condensed consolidated balance sheets:
March 31, 2021December 31, 2020
Carrying ValueFair ValueCarrying ValueFair Value
(In thousands)
Debt:
Revolving credit facility$57,000 $57,000 $84,000 $84,000 
5.375% senior notes due 2027(1)
$471,911 $500,719 $471,644 $501,439 
(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 Notes was determined using the March 31, 2021 quoted market price, a Level 1 classification in the fair value hierarchy.

Fair Value of Financial Assets

The Partnership has other financial instruments consisting of cash and cash equivalents, royalty income receivable, other current assets, accounts payable and accrued liabilities. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.

12.    COMMITMENTS AND CONTINGENCIES

The Partnership is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary 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’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. 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.

13

Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


13.    SUBSEQUENT EVENTS

Cash Distribution

On April 27, 2021, the board of directors of the General Partner approved a cash distribution for the first quarter of 2021 of $0.25 per common unit, payable on May 20, 2021, to eligible unitholders of record at the close of business on May 13, 2021.

14

ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are a publicly traded Delaware limited partnership formed by Diamondback to own and acquire mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin. We operate in one reportable segment. Since May 10, 2018, we have been treated as a corporation for U.S. federal income tax purposes.

As of March 31, 2021, our general partner held a 100% general partner interest in us, and Diamondback owned 731,500 of our common units and beneficially owned all of our 90,709,946 outstanding Class B units, representing approximately 59% of our total units outstanding. Diamondback also owns and controls our general partner.

Recent Developments

COVID-19 and Commodity Prices

In early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels, as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the ongoing COVID-19 pandemic. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in response to the increase in demand. During 2020 and 2021, the posted price for West Texas intermediate light sweet crude oil, or NYMEX WTI, has ranged from $(37.63) to $66.09 Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $1.48 to $3.35 per MMBtu. On April 12, 2021, the closing NYMEX WTI price for crude oil was $59.70 per Bbl and the closing NYMEX Henry Hub price of natural gas was $2.56 per MMBtu. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices.

As a result of the reduction in crude oil demand caused by factors discussed above, Diamondback and other operators on properties in which we have mineral and royalty interests lowered their 2020 capital budgets and production guidance however, Diamondback and certain of our other operators have since restored curtailed production. We cannot reasonably predict whether production levels will remain at current levels or the impact the full extent of the events above and subsequent recovery may have on our industry and our business.

Based on the results of the quarterly ceiling test, we were not required to record an impairment on our proved oil and natural gas interests for the quarter ended March 31, 2021. If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices fail to stabilize or decrease further, our production, proved reserves and cash flows will be adversely impacted. Our business may be also further adversely impacted by any pipeline capacity and storage constraints.

Acquisitions and Divestitures Update

We had immaterial additions to mineral and royalty interests during the first quarter of 2021, leaving our footprint of mineral and royalty interests at a total of 24,350 royalty acres at March 31, 2021.

Cash Distributions on Common Units

On April 27, 2021, the board of directors of our general partner declared a cash distribution for the three months ended March 31, 2021 of $0.25 per common unit, increasing our distribution for the first quarter of 2021 to 60% of cash available for distribution. The distribution is payable on May 20, 2021 to eligible common unitholders of record at the close of business on May 13, 2021. With net debt decreasing in the third quarter of 2020 from peak levels due to strong free cash flow generation, as well as an improved forward outlook for production, realized pricing and free cash flow yield, driven primarily by
15

Diamondback’s anticipated development plan and benefiting from our hedging arrangements rolling off in 2021, we expect to continue to increase our return on capital to unitholders in future quarters.

Production and Operational Update

Our business has rebounded strongly from the unprecedented volatility experienced throughout 2020 as commodity prices increased and activity has returned to our acreage. There are currently 29 rigs operating on our mineral and royalty acreage, four of which are operated by Diamondback. Our production and free cash flow outlook is expected to be driven by Diamondback’s continued focus on developing our acreage, as well as our exposure to other well-capitalized operators in the Permian Basin. Despite the adversity presented by Winter Storm Uri in February 2021, we produced a strong first quarter as production fully returned from the negative impacts of the severe weather and Diamondback quickly resumed completion operations. We expect production to remain strong throughout the remainder of 2021, particularly in the second half of 2021, as Diamondback plans to complete more wells with a higher interest net to us and third-party activity is expected to continue to strengthen relative to the levels experienced over the past several quarters. As a result, we have increased our production outlook for the full year 2021, based on our visibility into Diamondback’s expected forward development plan, which includes several large pads in which we will own a significant royalty interest.

The following table summarizes our gross well information as of April 12, 2021:
Diamondback OperatedThird Party OperatedTotal
Horizontal wells turned to production (first quarter 2021)(1):
Gross wells5084134
Net 100% royalty interest wells2.10.42.5
Average percent net royalty interest4.2 %0.5 %1.9 %
Horizontal producing well count (as of April 12, 2021):
Gross wells1,1913,5144,705
Net 100% royalty interest wells90.753.4144.2
Average percent net royalty interest7.6 %1.5 %3.1 %
Horizontal active development well count (as of April 12, 2021)(2):
Gross wells65406471
Net 100% royalty interest wells5.82.98.7
Average percent net royalty interest9.0 %0.7 %1.8 %
Line of sight wells (as of April 12, 2021)(3):
Gross wells101389490
Net 100% royalty interest wells5.23.58.7
Average percent net royalty interest5.1 %0.9 %1.8 %

(1) Average lateral length of 10,584.
(2) The total 471 gross wells currently in the process of active development are those wells that have been spud and are expected to be turned to production within approximately the next six to eight months.
(3) The total 490 gross line-of-sight wells are those that are not currently in the process of active development, but for which we have reason to believe that they will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our royalty acreage does not ensure that those wells will be turned to production given the current depressed oil prices.

16

Results of Operations

The following table summarizes our income and expenses for the periods indicated:

Three Months Ended March 31,
20212020
 (In thousands)
Operating income:
Oil income$78,344 $72,200 
Natural gas income9,044 344 
Natural gas liquids income9,124 4,285 
Royalty income96,512 76,829 
Lease bonus income325 1,622 
Other operating income139 241 
Total operating income96,976 78,692 
Costs and expenses:
Production and ad valorem taxes6,649 6,147 
Depletion24,886 24,642 
General and administrative expenses2,221 2,666 
Total costs and expenses33,756 33,455 
Income (loss) from operations63,220 45,237 
Other income (expense):
Interest expense, net(7,860)(8,963)
Gain (loss) on derivative instruments, net(31,504)(7,942)
Gain (loss) on revaluation of investment— (10,120)
Other income, net38 404 
Total other expense, net(39,326)(26,621)
Income (loss) before income taxes23,894 18,616 
Provision for (benefit from) income taxes35 142,466 
Net income (loss)23,859 (123,850)
Net income (loss) attributable to non-controlling interest26,879 18,319 
Net income (loss) attributable to Viper Energy Partners LP$(3,020)$(142,169)
17

The following table summarizes our production data, average sales prices and average costs for the periods indicated:

Three Months Ended March 31,
20212020
Production Data:
Oil (MBbls)1,395 1,587 
Natural gas (MMcf)3,262 2,658 
Natural gas liquids (MBbls)407 479 
Combined volumes (MBOE)(1)
2,346 2,509 
Average daily oil volumes (BO/d)(2)
15,500 17,441 
Average daily combined volumes (BOE/d)(2)
26,066 27,575 
Average sales prices(2):
Oil ($/Bbl)$56.16 $45.49 
Natural gas ($/Mcf)$2.77 $0.13 
Natural gas liquids ($/Bbl)$22.42 $8.94 
Combined ($/BOE)$41.14 $30.62 
Oil, hedged ($/Bbl)(3)
$45.45 $45.49 
Natural gas, hedged ($/Mcf)(3)
$2.77 $(0.04)
Natural gas liquids ($/Bbl)(3)
$22.42 $8.94 
Combined price, hedged ($/BOE)(3)
$34.77 $30.44 
Average costs ($/BOE):
Production and ad valorem taxes$2.83 $2.45 
General and administrative - cash component(4)
0.81 0.91 
Total operating expense - cash$3.64 $3.36 
General and administrative - non-cash unit compensation expense$0.13 $0.15 
Interest expense, net$3.35 $3.57 
Depletion$10.61 $9.82 
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)Average daily volumes and average sales prices presented are based on actual production volumes and not calculated utilizing the rounded production volumes presented in the table above.
(3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices.
(4)Excludes non-cash unit-based compensation expense for the respective periods presented.

18

Comparison of the Three Months Ended March 31, 2021 and 2020

Royalty Income

Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes.

The increase in average prices received during the three months ended March 31, 2021 as compared to the same period in 2020 contributed to $29.0 million of the total $19.7 million increase in royalty income. This was slightly offset by a 7% decrease in combined volumes sold by our operators as compared to the three months ended March 31, 2020 primarily resulting from the recent winter storms in the Permian Basin. The storms caused the loss of approximately four to five days of total net production during February 2021 for Diamondback operated properties, with a slightly higher negative impact expected for third party operated properties. Diamondback has indicated it expects to make up these production losses throughout 2021.

Production and Ad Valorem Taxes

The following table presents the production and ad valorem taxes for the three months ended March 31, 2021 and 2020:

Three Months Ended March 31,
20212020
Amount
(In thousands)
Per BOEPercentage of Royalty IncomeAmount
(In thousands)
Per BOEPercentage of Royalty Income
Production taxes$4,823 $2.05 5.0 %$3,575 $1.43 4.7 %
Ad valorem taxes1,826 0.78 1.9 2,572 1.02 3.3 
Total production and ad valorem taxes$6,649 $2.83 6.9 %$6,147 $2.45 8.0 %

Production taxes as a percentage of royalty income for the three months ended March 31, 2021 remained consistent with the three months ended March 31, 2020. Ad valorem taxes as a percentage of royalty income for these same periods in 2021 compared to 2020 decreased primarily due to improved average sales prices, while the tax valuation of oil and natural gas interest remained fairly flat.

Depletion

Depletion expense increased $0.2 million, or 1%, for the three months ended March 31, 2021 compared to the same period in 2020. The average depletion rate increased to $10.61 per BOE for the three months ended March 31, 2021 compared to $9.82 per BOE for the three months ended March 31, 2020. This rate increase largely resulted from lower SEC oil prices utilized in the reserve calculations in the 2021 period, shortening the economic life of the reserve base and resulted in lower projected remaining reserve volumes on our wells.

Net Interest Expense

Net interest expense for the three months ended March 31, 2021 and 2020 totaled $7.9 million and $9.0 million, respectively. The decrease of $1.1 million was due primarily to our repayment of borrowings under the Operating Company’s revolving credit facility and our repurchase of $20.1 million of the Notes during the second and third quarters of 2020.

Derivative Instruments

We recorded a loss on derivative instruments for the three months ended March 31, 2021 and 2020 of $31.5 million and $7.9 million, respectively, which includes cash payments of $14.9 million and $0.5 million on settlements of commodity derivative contracts during the respective periods. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our condensed consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.”

19

Gain (Loss) on Revaluation of Investment

We did not record a gain or loss on revaluation of investment for the three months ended March 31, 2021, as we divested our equity interest in a limited partnership during the third and fourth quarters of 2020. We recorded a loss on revaluation of investment of $10.1 million for the three months ended March 31, 2020.

Provision for (Benefit from) Income Taxes

We recorded an immaterial income tax expense for the three months ended March 31, 2021 due to maintaining a valuation allowance against our deferred tax assets, partially offset by current income tax expense for the period, and recorded income tax expense of $142.5 million for the three months ended March 31, 2020 due to recording a valuation allowance against our deferred tax assets.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our common unitholders.

We define Adjusted EBITDA as net income (loss) attributable to Viper Energy Partners LP plus net income (loss) attributable to non-controlling interest (“net income (loss)”) before interest expense, net, non-cash unit-based compensation expense, depletion expense, impairment expense, (gain) loss on revaluation of investment, non-cash (gain) loss on derivative instruments, and provision for (benefit from) income taxes, if any. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

The GAAP measure most directly comparable to Adjusted EBITDA is net income. However, Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP and should not be considered an alternative to, or more meaningful than, net income (loss), royalty income, cash flow from operating activities or any other measure of financial performance or liquidity presented as determined in accordance with GAAP. Our computations of Adjusted EBITDA excludes some, but not all, items that affect net income (loss), and these measures may vary from those of other companies. As a result, Adjusted EBITDA as presented below may not be comparable to other similarly titled measures of other companies.

20

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measures of Adjusted EBITDA and cash available for distribution for the periods indicated:
Three Months Ended March 31,
20212020
(In thousands)
Net income (loss) attributable to Viper Energy Partners LP$(3,020)$(142,169)
Net income (loss) attributable to non-controlling interest26,879 18,319 
Net income (loss)23,859 (123,850)
Interest expense, net7,860 8,963 
Non-cash unit-based compensation expense315 387 
Depletion24,886 24,642 
(Gain) loss on revaluation of investment— 10,120 
Non-cash (gain) loss on derivative instruments16,562 7,489 
Provision for (benefit from) income taxes35 142,466 
Consolidated Adjusted EBITDA73,517 70,217 
Less: Adjusted EBITDA attributable to non-controlling interest(1)
42,779 40,175 
Adjusted EBITDA attributable to Viper Energy Partners LP$30,738 $30,042 
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
Income taxes payable$(35)$— 
Debt service, contractual obligations, fixed charges and reserves(3,047)(3,383)
Cash paid for tax withholding on vested common units(20)(383)
Distribution equivalent rights payments(24)(20)
Preferred distributions(45)(45)
Cash available for distribution to Viper Energy Partners LP unitholders$27,567 $26,211 
Common limited partner units outstanding64,950 67,831 
Cash available for distribution per limited partner unit$0.42 $0.39 
Cash per unit approved for distribution$0.25 $0.10 
(1) Does not take into account special income allocation consideration.

Cash Distributions

The distribution for the first quarter of 2021 of $0.25 per common unit is payable on May 20, 2021 to common unitholders of record at the close of business on May 13, 2021. See Note 7—Unitholders' Equity and Distributions for further discussion of our distributions.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity have been cash flows from operations, proceeds from sales of non-core assets and investments, equity and debt offerings and borrowings under our credit agreement. Our primary uses of cash have been distributions to our unitholders, repayment of debt and capital expenditures for the acquisition of our mineral interests and royalty interests in oil and natural gas properties, and repurchases of our common units. We intend to finance future expenditures through a combination of cash on hand, borrowings under our credit agreement, issuance of common units and, subject to market conditions and other factors, proceeds from one or more capital market transactions, which may include debt or equity offerings.

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Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices and general economic, financial, competitive, legislative, regulatory and other factors, including extreme weather conditions, such as the recent severe winter storms in the Permian Basin that impacted production volumes on our mineral and royalty acreage. Continued prolonged volatility in the capital, financial and/or credit markets, depressed commodity prices and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Cash Flows

The following table presents our cash flows for the periods indicated:
Three Months Ended March 31,
20212020
(In thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities$54,659 $96,111 
Net cash provided by (used in) investing activities(74)(64,626)
Net cash provided by (used in) financing activities(61,979)5,184 
Net increase (decrease) in cash$(7,394)$36,669 

Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volume of oil and natural gas sold by our producers. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. The decrease in net cash provided by operating activities during the three months ended March 31, 2021, was primarily due to an increase in cash paid for derivative settlements and changes in our working capital accounts, most notably through an increase in our accounts receivable. These were partially offset by the increase in royalty income as discussed in “—Results of Operations” above.

Investing Activities

Net cash used in investing activities during the three months ended March 31, 2021 and 2020, was primarily related to acquisitions of oil and natural gas interests.

Financing Activities

Net cash used in financing activities during the three months ended March 31, 2021, was primarily related to the repayment of $27.0 million of borrowings under the Operating Company’s revolving credit facility, distributions of $21.9 million to our unitholders and $13.0 million of repurchases of our common units during the first quarter of 2021 as discussed below.

Net cash provided by financing activities was $5.2 million during the three months ended March 31, 2020, primarily related to net borrowing activity under the Operating Company’s revolving credit facility of $77.0 million and partially offset by distributions of $71.4 million to our unitholders during the period.

Common Unit Repurchase Program

On November 6, 2020, the board of directors of our general partner approved an expansion of our return of capital program with the implementation of a common unit repurchase program to acquire up to $100.0 million of our outstanding common units. During the three months ended March 31, 2021, we repurchased approximately $13.0 million of common units under our repurchase program. As of March 31, 2021, $62.9 million remains available for us to repurchase units under our common unit repurchase program. The common unit repurchase program is authorized to extend through December 31, 2021 and we intend to purchase common units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. The repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of our general partner at any time.

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Indebtedness

At March 31, 2021, our indebtedness consists of $479.9 million in principal amount of Notes outstanding and borrowings under the Operating Company’s revolving credit facility. The Operating Company’s credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $580.0 million as of March 31, 2021, based on the Operating Company’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November. As of March 31, 2021, there was $57.0 million of outstanding borrowings and $523.0 million available for future borrowings under the Operating Company’s revolving credit facility. During the three months ended March 31, 2021, the weighted average interest rate on the Operating Company’s revolving credit facility was 1.88%. The revolving credit facility will mature on November 1, 2022.

As of March 31, 2021, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement.

See additional discussion of our indebtedness in Note 6—Debt.

Contractual Obligations

Other than the changes in our outstanding debt discussed in Note 6—Debt, there were no material changes in our contractual obligations and other commitments as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.

Critical Accounting Policies

There have been no changes to our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized prices are driven primarily by the prevailing worldwide price for crude oil and prices for natural gas in the United States. Both crude oil and natural gas realized prices are also impacted by the quality of the product, supply and demand balances in local physical markets and the availability of transportation to demand centers. Pricing for oil and natural gas production has been historically volatile and unpredictable and the prices that our operators receive for production depend on many factors outside of our or their control. Further, oil prices dropped sharply in early March 2020 and then continued to decline, briefly reaching negative levels. This was as a result of multiple factors affecting supply and demand in the global oil and natural gas markets, including actions taken by OPEC members and other exporting nations, and a significant decrease in demand due to the ongoing COVID-19 pandemic, which resulted in a widespread health crisis and significant volatility, uncertainty and turmoil in the global economy, financial markets and oil and natural gas industry. Although market prices for oil and natural gas have recently increased, we cannot predict events that may lead to future price volatility.

We historically have used 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 our royalty income. Under our 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 us and when the settlement price is above the ceiling price, we are required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

At March 31, 2021, we had a net liability derivative position related to our commodity price derivatives of $43.2 million. Utilizing actual derivative contractual volumes under our fixed price swaps as of March 31, 2021, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $47.6 million, an increase of $4.4 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position to $38.7 million, a decrease of $4.4 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Credit Risk

We are subject to risk resulting from the concentration of royalty income in producing oil and natural gas interests and receivables with a limited number of significant purchasers and producers. We do not require collateral and the failure or inability of our significant purchasers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. Depressed commodity pricing environment and adverse macroeconomic conditions may enhance our purchaser credit risk.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under the Operating Company’s credit agreement. The terms of the credit agreement provide for interest on borrowings at a floating rate 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% in the case of the alternative base rate and from 1.75% to 2.75% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We entered into this credit agreement on July 8, 2014, as subsequently amended, and as of March 31, 2021, we had $57.0 million in outstanding borrowings. During the three months ended March 31, 2021, the weighted average interest rate on the Operating Company’s revolving credit facility was 1.88%.

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ITEM 4.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures. Under the direction of the Chief Executive Officer and Chief Financial Officer of our general partner, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our general partner, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of March 31, 2021, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner have concluded that as of March 31, 2021, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.     LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Note 12—Commitments and Contingencies.

ITEM 1A.     RISK FACTORS

Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.

In addition to the information set forth in this report, you should carefully consider the risk factors disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020, and in subsequent filings we make with the SEC. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2020.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common unit repurchase activity for the three months ended March 31, 2021 was as follows:

Period
Total Number of Units Purchased(1)
Average Price Paid Per Unit(2)
Total Number of Units Purchased as Part of Publicly Announced Plan
Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(3)
(In thousands, except unit amounts)
January 1, 2021 - January 31, 2021355,000$13.99 355,000$71,009 
February 1, 2021 - February 28, 2020189,453$15.24 189,453$68,122 
March 1, 2021 - March 31, 2021326,956$15.95 325,512$62,931 
Total871,409$15.00 869,965
(1)Includes common units repurchased from employees in order to satisfy tax withholding requirements. Such units are cancelled and retired immediately upon repurchase.
(2)The average price paid per common unit is net of any commissions paid to repurchase common unit.
(3)In November 2020, our board of directors approved a common unit repurchase program to acquire up to $100.0 million of our outstanding common units through December 31, 2021. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of our general partner at any time.
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ITEM 6.     EXHIBITS
Exhibit NumberDescription
3.1
3.2
3.3
3.4
3.5
4.1
31.1*
31.2*
32.1**
101The following financial information from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement of Changes in Unitholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Condensed Notes to Consolidated Financial Statements.
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*Filed herewith.
**The certifications attached as Exhibit 32.1 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

VIPER ENERGY PARTNERS LP
By:VIPER ENERGY PARTNERS GP LLC
its General Partner
Date:May 5, 2021By:/s/ Travis D. Stice
Travis D. Stice
Chief Executive Officer
Date:May 5, 2021By:/s/ Teresa L. Dick
Teresa L. Dick
Chief Financial Officer

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