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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 September 30, 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)
DE
46-5001985
(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification Number)
500 West Texas
Suite 1200
Midland, TX
79701
(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 class Trading Symbol(s) Name of each exchange on which registered
Common Units VNOM The 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 Filer ☒ Accelerated Filer ☐
Non-Accelerated Filer ☐ Smaller 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 October 29, 2021, the registrant had outstanding 79,120,603 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 SEPTEMBER 30, 2021
TABLE OF CONTENTS
Page
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iii
iv
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33

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”):
Basin A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BO One barrel of oil.
BO/d BO per day.
BOE One barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d BOE per day.
British Thermal Unit or Btu The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Condensate Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Horizontal wells Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBbls Thousand barrels of crude oil or other liquid hydrocarbons.
MBOE One 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.
Mcf One thousand cubic feet of natural gas.
Mineral interests The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu One million British Thermal Units.
Net royalty acres Gross acreage multiplied by the average royalty interest.
Oil and natural gas properties Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Prospect A 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 reserves The 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.
Reserves The 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).
Reservoir A 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 interest An 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.
Spud Commencement of actual drilling operations.
WTI West Texas Intermediate.
ii
GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report:
ASU Accounting Standards Update.
Diamondback Diamondback Energy, Inc., a Delaware corporation.
Exchange Act The Securities Exchange Act of 1934, as amended.
GAAP Accounting principles generally accepted in the United States.
General Partner Viper Energy Partners GP LLC, a Delaware limited liability company, and the General Partner of the Partnership.
LIBOR The London interbank offered rate.
LTIP Viper Energy Partners LP Long Term Incentive Plan.
NYMEX New York Mercantile Exchange.
OPEC Organization of the Petroleum Exporting Countries.
Operating Company Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy Partners LP.
Partnership Viper Energy Partners LP, a Delaware limited partnership.
SEC United States Securities and Exchange Commission.
The Notes
The 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 and 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 COVID-19 pandemic and its impact on the oil and natural gas industry, pricing and demand for oil and natural gas and the supply chain disruptions;
•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 on our industry and business;
•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, any 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, including our recently completed Swallowtail Acquisition described in this report;
•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 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)
September 30, December 31,
2021 2020
(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents $ 41,515  $ 19,121 
Royalty income receivable (net of allowance for credit losses) 47,133  32,210 
Royalty income receivable—related party 22,022  1,998 
Other current assets 654  665 
Total current assets 111,324  53,994 
Property:
Oil and natural gas interests, full cost method of accounting ($1,296,765 and $1,364,906 excluded from depletion at September 30, 2021 and December 31, 2020, respectively)
2,902,270  2,895,542 
Land 5,688  5,688 
Accumulated depletion and impairment (570,406) (496,176)
Property, net 2,337,552  2,405,054 
Funds held in escrow 30,025  — 
Other assets 3,567  2,327 
Total assets $ 2,482,468  $ 2,461,375 
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable $ 208  $ 43 
Accrued liabilities 26,000  18,262 
Derivative instruments 35,357  26,593 
Total current liabilities 61,565  44,898 
Long-term debt, net 564,452  555,644 
Derivative instruments 697  — 
Total liabilities 626,714  600,542 
Commitments and contingencies (Note 12)
Unitholders’ equity:
General partner 749  809 
Common units (63,830,715 units issued and outstanding as of September 30, 2021 and 65,817,281 units issued and outstanding as of December 31, 2020)
580,992  633,415 
Class B units (90,709,946 units issued and outstanding as of September 30, 2021 and December 31, 2020)
956  1,031 
Total Viper Energy Partners LP unitholders’ equity 582,697  635,255 
Non-controlling interest 1,273,057  1,225,578 
Total equity 1,855,754  1,860,833 
Total liabilities and unitholders’ equity $ 2,482,468  $ 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 September 30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands, except per unit amounts)
Operating income:
Royalty income $ 127,649  $ 62,584  $ 337,619  $ 171,857 
Lease bonus income 223  40  1,032  1,685 
Other operating income 132  318  479  761 
Total operating income 128,004  62,942  339,130  174,303 
Costs and expenses:
Production and ad valorem taxes 8,625  5,049  23,426  14,306 
Depletion 25,366  24,780  74,230  72,204 
General and administrative expenses 1,735  1,811  6,118  6,160 
Total costs and expenses 35,726  31,640  103,774  92,670 
Income (loss) from operations 92,278  31,302  235,356  81,633 
Other income (expense):
Interest expense, net (8,328) (8,238) (24,161) (24,870)
Gain (loss) on derivative instruments, net (9,599) (5,084) (70,649) (47,469)
Gain (loss) on revaluation of investment —  (1,984) —  (8,661)
Other income, net —  188  77  1,111 
Total other expense, net (17,927) (15,118) (94,733) (79,889)
Income (loss) before income taxes 74,351  16,184  140,623  1,744 
Provision for (benefit from) income taxes 906  —  941  142,466 
Net income (loss) 73,445  16,184  139,682  (140,722)
Net income (loss) attributable to non-controlling interest 56,613  16,948  121,208  23,963 
Net income (loss) attributable to Viper Energy Partners LP $ 16,832  $ (764) $ 18,474  $ (164,685)
Net income (loss) attributable to common limited partner units:
Basic $ 0.26  $ (0.01) $ 0.29  $ (2.43)
Diluted $ 0.26  $ (0.01) $ 0.29  $ (2.43)
Weighted average number of common limited partner units outstanding:
Basic 64,152  67,847  64,724  67,832 
Diluted 64,241  67,847  64,815  67,832 














See accompanying notes to condensed consolidated financial statements.
2
Viper Energy Partners LP
Condensed Consolidated Statements of Changes to Unitholders' Equity
(Unaudited)

Limited Partners General Partner Non-Controlling Interest
Common Class B Amount Amount
Units Amount Units Amount Total
(In thousands)
Balance at December 31, 2020 65,817  $ 633,415  90,710  $ 1,031  $ 809  $ 1,225,578  $ 1,860,833 
Unit-based compensation —  315  —  —  —  —  315 
Issuance of common units 3  —  —  —  —  —  — 
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, 2021 64,950  611,172  90,710  1,006  789  1,237,071  1,850,038 
Unit-based compensation —  338  —  —  —  —  338 
Distribution equivalent rights payments —  (55) —  —  —  —  (55)
Distributions to public —  (15,992) —  —  —  —  (15,992)
Distributions to Diamondback —  (183) —  (25) —  (22,678) (22,886)
Distributions to General Partner —  —  —  —  (20) —  (20)
Change in ownership of consolidated subsidiaries, net —  1,614  —  —  (1,614) — 
Repurchased units as part of unit buyback (404) (6,779) —  —  —  —  (6,779)
Net income (loss) —  4,662  —  —  —  37,716  42,378 
Balance at June 30, 2021 64,546  594,777  90,710  981  769  1,250,495  1,847,022 
Unit-based compensation —  243  —  —  —  —  243 
Issuance of common units 50  —  —  —  —  —  — 
Distribution equivalent rights payments —  (62) —  —  —  —  (62)
Distributions to public —  (20,933) —  —  —  —  (20,933)
Distributions to Diamondback —  (240) —  (25) —  (29,936) (30,201)
Distributions to General Partner —  —  —  —  (20) —  (20)
Change in ownership of consolidated subsidiaries, net —  4,115  —  —  —  (4,115) — 
Repurchased units as part of unit buyback (765) (13,740) —  —  —  —  (13,740)
Net income (loss) —  16,832  —  —  —  56,613  73,445 
Balance at September 30, 2021 63,831  $ 580,992  90,710  $ 956  $ 749  $ 1,273,057  $ 1,855,754 


See accompanying notes to condensed consolidated financial statements.
3
Viper Energy Partners LP
Condensed Consolidated Statements of Changes to Unitholders' Equity - (Continued)
(Unaudited)

Limited Partners General Partner Non-Controlling Interest
Common Class B Amount Amount
Units Amount Units Amount Total
(In thousands)
Balance at December 31, 2019 67,806  $ 929,116  90,710  $ 1,130  $ 889  $ 1,254,285  $ 2,185,420 
Unit-based compensation —  387  —  —  —  —  387 
Issuance of common units 25  —  —  —  —  —  — 
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, 2020 67,831  756,408  90,710  1,105  869  1,231,785  1,990,167 
Unit-based compensation —  283  —  —  —  —  283 
Distribution equivalent rights payments —  (4) —  —  —  —  (4)
Distributions to public —  (6,710) —  —  —  —  (6,710)
Distributions to Diamondback —  (76) —  (25) —  (9,074) (9,175)
Distributions to General Partner —  —  —  —  (20) —  (20)
Net income (loss) —  (21,752) —  —  —  (11,304) (33,056)
Balance at June 30, 2020 67,831  728,149  90,710  1,080  849  1,211,407  1,941,485 
Unit-based compensation —  275  —  —  —  —  275 
Issuance of common units 20  —  —  —  —  —  — 
Distribution equivalent rights payments —  (2) —  —  —  —  (2)
Distributions to public —  (2,013) —  —  —  —  (2,013)
Distributions to Diamondback —  (19) —  (25) —  (2,720) (2,764)
Distributions to General Partner —  —  —  (20) —  (20)
Units repurchased for tax withholding —  (1) —  —  —  —  (1)
Net income (loss) —  (764) —  —  —  16,948  16,184 
Balance at September 30, 2020 67,851  $ 725,625  90,710  $ 1,055  $ 829  $ 1,225,635  $ 1,953,144 












See accompanying notes to condensed consolidated financial statements.
4
Viper Energy Partners LP
Condensed Consolidated Statements of Cash Flows
(Unaudited)

Nine Months Ended September 30,
2021 2020
(In thousands)
Cash flows from operating activities:
Net income (loss) $ 139,682  $ (140,722)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense (benefit) —  142,466 
Depletion 74,230  72,204 
(Gain) loss on derivative instruments, net 70,649  47,469 
Net cash receipts (payments) on derivatives (61,188) (18,718)
(Gain) loss on revaluation of investment —  8,661 
Other 3,332  2,681 
Changes in operating assets and liabilities:
Royalty income receivable (14,923) 25,981 
Royalty income receivable—related party (20,024) (4,335)
Other 7,914  7,519 
Net cash provided by (used in) operating activities 199,672  143,206 
Cash flows from investing activities:
Acquisitions of oil and natural gas interests (6,728) (64,508)
Other —  7,360 
Net cash provided by (used in) investing activities (6,728) (57,148)
Cash flows from financing activities:
Proceeds from borrowings under credit facility 87,000  95,000 
Repayment on credit facility (79,000) (65,000)
Repayment of senior notes —  (19,697)
Repurchased units as part of unit buyback (33,562) — 
Distributions to public (46,102) (38,943)
Distributions to Diamondback (65,913) (53,112)
Other (2,948) (534)
Net cash provided by (used in) financing activities (140,525) (82,286)
Net increase (decrease) in cash and cash equivalents 52,419  3,772 
Cash, cash equivalents and restricted cash at beginning of period 19,121  3,602 
Cash, cash equivalents and restricted cash at end of period $ 71,540  $ 7,374 















See accompanying notes to condensed consolidated financial statements.
5
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 September 30, 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 one 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 as of 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 and an increase in demand in the second half of 2020 and into 2021. However, the COVID-19 Delta variant emerged in March 2021 and became highly transmissible in July 2021, which contributed to additional pricing volatility during the third quarter of 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.

6
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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, 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.

Cash, Cash Equivalents and Restricted Cash

Reconciliation of cash, cash equivalents and restricted cash as presented on the condensed consolidated statements of cash flows for the periods presented:

Nine Months Ended September 30,
2021 2020
(In thousands)
Cash and cash equivalents $ 41,515  $ 7,374 
Restricted cash(1)
30,025  — 
Total cash, cash equivalents and restricted cash $ 71,540  $ 7,374 
(1)Escrow deposit related to the Swallowtail Acquisition, which is included in Funds held in escrow in the condensed consolidated balance sheets as discussed further in Note 13—Subsequent Events.

Accrued Liabilities

Accrued liabilities consist of the following:

September 30, December 31,
2021 2020
(In thousands)
Interest payable $ 10,799  $ 4,311 
Ad valorem taxes payable 5,868  6,501 
Derivatives instruments payable 8,550  7,392 
Other 783  58 
Total accrued liabilities $ 26,000  $ 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, previously disclosed, or not material upon adoption.

7
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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 September 30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands)
Oil income $ 100,154  $ 53,595  $ 272,450  $ 153,412 
Natural gas income 12,074  3,331  30,651  4,909 
Natural gas liquids income 15,421  5,658  34,518  13,536 
Total royalty income $ 127,649  $ 62,584  $ 337,619  $ 171,857 

4.    ACQUISITIONS

2021 Activity

The Partnership had no significant acquisition or divestiture activity during the nine months ended September 30, 2021.

See Note 13—Subsequent Events for further discussion of acquisitions in the fourth quarter of 2021.

2020 Activity

During the nine months ended September 30, 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:

September 30, December 31,
2021 2020
(In thousands)
Oil and natural gas interests:
Subject to depletion $ 1,605,505  $ 1,530,636 
Not subject to depletion 1,296,765  1,364,906 
Gross oil and natural gas interests 2,902,270  2,895,542 
Accumulated depletion and impairment (570,406) (496,176)
Oil and natural gas interests, net 2,331,864  2,399,366 
Land 5,688  5,688 
Property, net of accumulated depletion and impairment $ 2,337,552  $ 2,405,054 

8
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
As of September 30, 2021 and December 31, 2020, the Partnership had mineral and royalty interests representing 24,368 and 24,350 net royalty acres, respectively.

No impairment expense was recorded on the Partnership’s oil and gas properties for the three and nine months ended September 30, 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:

September 30, December 31,
2021 2020
(In thousands)
5.375% senior notes due 2027
$ 479,938  $ 479,938 
Revolving credit facility 92,000  84,000 
Unamortized debt issuance costs (1,832) (2,058)
Unamortized discount (5,654) (6,236)
Total long-term debt $ 564,452  $ 555,644 

The Operating Company’s Revolving Credit Facility

On June 2, 2021, the Operating Company entered into the seventh amendment to the existing credit agreement, which maintained the maximum amount of the revolving credit facility at $2.0 billion and reaffirmed the borrowing base of $580.0 million based on the Operating Company’s oil and natural gas reserves and other factors, and added new provisions that allow the Operating Company to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be redetermined semi-annually in May and November, and is expected to be reaffirmed at $580.0 million by the lenders during the regularly scheduled (semi-annual) fall 2021 redetermination in November 2021. As of September 30, 2021, the Operating Company had elected a commitment amount of $500.0 million, with $92.0 million of outstanding borrowings and $408.0 million available for future borrowings under the Operating Company’s revolving credit facility. The revolving credit facility will mature on June 2, 2025.

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 1.00% to 2.00% per annum in the case of the alternative base rate and from 2.00% to 3.00% per annum in the case of LIBOR, in each case depending on the amount of the loans outstanding in relation to the commitment, which is calculated using the least of the maximum credit amount, the aggregate elected commitment 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. 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. The loan is secured by substantially all the assets of the Partnership and the Operating Company. During the three and nine months ended September 30, 2021 and 2020, the weighted average interest rate on the Operating Company’s revolving credit facility was 1.98%, 2.14%, 2.14% and 2.66%, respectively.

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, excess cash and entering into certain swap agreements and require the maintenance of the financial ratios described below. The amendment to the credit agreement added a financial covenant requirement for the ratio of secured debt to EBITDAX as included below.
9
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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
Ratio of secured debt to EBITDAX, as defined in the credit agreement
Not greater than 2.5 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 September 30, 2021, 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 Operating Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. 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.

2027 Senior Notes

The Partnership’s 5.375% senior notes due 2027 (the “Notes”) are senior unsecured obligations of the Partnership and are initially guaranteed on a senior unsecured basis by the Operating Company and pay interest semi-annually. Neither Diamondback nor the General Partner guarantees the Notes. In the future, each of the Partnership’s restricted subsidiaries that either (i) guarantees any of its or a guarantor’s other indebtedness or (ii) 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. As of September 30, 2021, $479.9 million in aggregate principal amount of the Notes was outstanding. The Partnership did not repurchase any Notes during the three or nine months ended September 30, 2021, but may do so opportunistically from time to time in future periods.

7.    UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has general partner and limited partner units. At September 30, 2021, the Partnership had a total of 63,830,715 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. At September 30, 2021, Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 59% 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).

See Note 13—Subsequent Events for further discussion of additional common units issued in the fourth quarter of 2021.

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, of which approximately $57.6 million has been expended through September 30, 2021. During the three and nine months ended September 30, 2021, the Partnership repurchased approximately $13.7 million and $33.6 million, respectively, of common units under the repurchase program authorized to extend through December 31, 2021. The repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of the General Partner at any time. Any common units under the repurchase program will be purchased opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events, such as the sale of assets. Any such repurchases may be made from time to time in open market or privately negotiated transactions in compliance with Rule 10b-18 under the Securities Exchange Act of 1934, as amended, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors.

10
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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.

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

Distributions
(In thousands)
Period Amount per Unit
Operating Company Distributions to Diamondback
Common Unitholders(1)
Declaration Date Unitholder Record Date Payment Date
Q4 2020 $ 0.14  $ 12,699  $ 9,162  February 19, 2021 March 4, 2021 March 11, 2021
Q1 2021 $ 0.25  $ 22,678  $ 16,230  April 27, 2021 May 13, 2021 May 20, 2021
Q2 2021 $ 0.33  $ 29,936  $ 21,235  July 28, 2021 August 12, 2021 August 19, 2021
(1)Includes $0.1 million, $0.2 million and $0.2 million paid to Diamondback for the fourth quarter of 2020 and the first and second quarters of 2021, respectively.

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 (loss) 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 September 30, 2021 Nine Months Ended September 30, 2021
(In thousands)
Net income (loss) attributable to the Partnership $ 16,832  $ 18,474 
Change in ownership of consolidated subsidiaries 4,115  8,416 
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest $ 20,947  $ 26,890 

There were no changes in ownership of consolidated subsidiaries during the three and nine months ended September 30, 2020.
11
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)

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 and nine months ended September 30, 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.

A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below:

Three Months Ended September 30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands, except per unit amounts)
Net income (loss) attributable to the period $ 16,832  $ (764) $ 18,474  $ (164,685)
Less: net income (loss) allocated to participating securities(1)
(62) (2) (141) (26)
Net income (loss) attributable to common unitholders $ 16,770  $ (766) $ 18,333  $ (164,711)
Weighted average common units outstanding:
Basic weighted average common units outstanding 64,152  67,847  64,724  67,832 
Effect of dilutive securities:
Potential common units issuable(2)
89  —  91  — 
Diluted weighted average common units outstanding 64,241  67,847  64,815  67,832 
Net income (loss) per common unit, basic $ 0.26  $ (0.01) $ 0.29  $ (2.43)
Net income (loss) per common unit, diluted $ 0.26  $ (0.01) $ 0.29  $ (2.43)
(1)    Distribution equivalent rights granted to employees are considered participating securities.
(2) For the nine months ended September 30, 2021, 2,955 potential common units were excluded from the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive. For the nine months ended September 30, 2020, no potential common units were included in 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.

As discussed further in Note 13—Subsequent Events—Swallowtail Acquisition, the Partnership issued 15.25 million additional common units as consideration for an acquisition in October 2021.
12
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
9.    INCOME TAXES

The following table provides the Partnership’s provision for (benefit from) income taxes and the effective income tax rate for the dates indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands, except for tax rate)
Provision for (benefit from) income taxes $ 906  $ —  $ 941  $ 142,466 
Effective tax rate 1.2  % —  % 0.7  % 8,168.9  %

The Partnership’s effective income tax rates for the three and nine months ended September 30, 2021 and 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 maintaining a valuation allowance on the Partnership’s deferred tax assets. For the nine months ended September 30, 2020, the Partnership also recorded discrete income tax expense of approximately $142.5 million related to application of a valuation allowance on the Partnership’s beginning-of-year deferred tax assets.

As of September 30, 2021 and 2020, the Partnership maintained a full valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets.

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. At September 30, 2021, the Partnership has costless collars and put options outstanding.

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.

Put options have a defined strike price, or floor price. The Partnership pays its counterparty a premium to enter into these derivative contracts, which are deferred until settlement. When the settlement price is below the floor price, the counterparty pays the Partnership an amount equal to the difference between the settlement price and the strike price multiplied by the derivative contract volume. When the settlement price is above the floor price, the put option expires worthless.

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 with natural gas derivative settlements based on the New York Mercantile Exchange Henry 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 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.
13
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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 September 30, 2021, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

Swaps Collars Puts
Settlement Month Settlement Year Type of Contract Bbls/Mcf Per Day Index Weighted Average Differential Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Strike Price
OIL
Oct. - Dec. 2021 Collars 10,000 WTI Cushing $— $— $30.00 $43.05 $—
Jan. - Mar. 2022 Collars 2,500 WTI Cushing $— $— $45.00 $79.55 $—
Apr. - Jun. 2022 Collars 2,000 WTI Cushing $— $— $45.00 $80.15 $—
Jan. - Mar. 2022
Puts(1)
9,500 WTI Cushing $— $— $— $— $47.51
Apr. - Jun. 2022
Puts(2)
8,000 WTI Cushing $— $— $— $— $47.50
NATURAL GAS
Jan. - Dec. 2022 Collars 20,000 Henry Hub $— $— $2.50 $4.62 $—
(1) Includes a deferred premium at a weighted average price of $1.57/Bbl.
(2) Includes a deferred premium at a weighted average price of $1.55/Bbl.

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 and the net cash receipts (payments) on derivatives for the periods presented:

Three Months Ended September 30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands)
Gain (loss) on derivative instruments $ (9,599) $ (5,084) $ (70,649) $ (47,469)
Net cash receipts (payments) on derivatives $ (25,306) $ (16,164) $ (61,188) $ (18,718)

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.
14
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)

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 September 30, 2021 and December 31, 2020. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

As of September 30, 2021
Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net Fair Value Presented in Balance Sheet
(In thousands)
Assets:
Current:
Derivative instruments $ —  $ 1,967  $ —  $ 1,967  $ (1,967) $ — 
Non-current:
Derivative instruments $ —  $ 102  $ —  $ 102  $ (102) $ — 
Liabilities:
Current:
Derivative instruments $ —  $ 37,324  $ —  $ 37,324  $ (1,967) $ 35,357 
Non-current:
Derivative instruments $ —  $ 799  $ —  $ 799  $ (102) $ 697 

15
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
As of December 31, 2020
Level 1 Level 2 Level 3 Total Gross Fair Value Gross Amounts Offset in Balance Sheet Net 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 Not Recorded at Fair Value

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

September 30, 2021 December 31, 2020
Carrying Value Fair Value Carrying Value Fair Value
(In thousands)
Debt:
Revolving credit facility $ 92,000  $ 92,000  $ 84,000  $ 84,000 
5.375% senior notes due 2027(1)
$ 472,452  $ 501,791  $ 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 September 30, 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.

16
Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)


13.    SUBSEQUENT EVENTS

Cash Distribution

On October 27, 2021, the board of directors of the General Partner approved a cash distribution for the third quarter of 2021 of $0.38 per common unit, payable on November 18, 2021, to eligible unitholders of record at the close of business on November 11, 2021.

Swallowtail Acquisition

On October 1, 2021, the Partnership and the Operating Company acquired certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC (the “Swallowtail entities”) pursuant to a definitive purchase and sale agreement for 15.25 million common units and approximately $225.0 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent 2,313 net royalty acres primarily in the Northern Midland Basin, of which 62% are operated by Diamondback. The Swallowtail Acquisition has an effective date of August 1, 2021. In accordance with the terms of the purchase agreement, the Partnership deposited $30.0 million into an escrow account in August 2021, which was released upon the closing of the transaction. The cash portion of this transaction was funded through a combination of cash on hand and approximately of $190.0 million borrowings under the Operating Company’s revolving credit facility. Following the completion of the Swallowtail Acquisition, Diamondback beneficially owned an approximate 54% of the Partnership’s total limited partner units outstanding.
17
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 September 30, 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 COVID-19 pandemic. Additionally, the Delta variant emerged in March 2021 and became highly transmissible in July 2021, which contributed to additional pricing and demand volatility during the third quarter of 2021. 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 $80.64 Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $1.48 to $6.31 per MMBtu. On October 13, 2021, the closing NYMEX WTI price for crude oil was $80.44 per Bbl and the closing NYMEX Henry Hub price of natural gas was $5.59 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. Although demand for oil and natural gas and commodity prices have recently increased, Diamondback and certain of our other operators have kept production on our acreage relatively flat during the first nine months of 2021, using excess cash flow for debt repayment and/or return to their stockholders rather than expanding their drilling programs. Diamondback also indicated that it intends to continue exercising capital discipline and maintaining its fourth quarter 2021 oil production flat in 2022. 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 September 30, 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 decrease, our production, proved reserves and cash flows may be adversely impacted. Our business may also be adversely impacted by any pipeline capacity and storage constraints.

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Acquisitions and Divestitures Update

Swallowtail Acquisition

On October 1, 2021, we completed the acquisition of certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC for approximately 15.25 million of our common units and approximately $225.0 million in cash. The mineral and royalty interests acquired in the Swallowtail Acquisition represent approximately 2,313 net royalty acres primarily in the Northern Midland Basin, of which approximately 62% are operated by Diamondback. The Swallowtail Acquisition has an effective date of August 1, 2021. We funded the cash portion of the purchase price for the Swallowtail Acquisition through a combination of cash on hand and approximately $190.0 million of borrowings under the Operating Company’s revolving credit facility.

As a result of the Swallowtail Acquisition, our footprint of mineral and royalty interests increased to a total of 26,281 net royalty acres at October 1, 2021.

Cash Distributions on Common Units

On October 27, 2021, the board of directors of our general partner declared a cash distribution for the three months ended September 30, 2021 of $0.38 per common unit, maintaining our distribution from the second quarter of 2021 of 70% of cash available for distribution. The distribution is payable on November 18, 2021 to eligible common unitholders of record at the close of business on November 11, 2021. Net debt decreased 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. These were primarily driven by Diamondback’s anticipated development plan and benefits from our 2021 hedging arrangements. We expect to continue to generate robust amounts of free cash flow and subsequently use that cash to both reduce debt and increase our return on capital to unitholders.

Production and Operational Update

Our business has rebounded strongly from the unprecedented volatility experienced throughout 2020 as commodity prices have increased and activity has returned to our acreage. Third party operated net wells turned to production on our acreage during the third quarter of 2021 are at their highest level since the first quarter of 2020. There are currently 35 rigs operating on our mineral and royalty acreage, five 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. We have increased our production outlook for 2021 and have a high level of visibility into Diamondback’s expected forward development plan that is expected to bolster oil production for Viper not only for the next several quarters, but in the coming years.

19
The following table summarizes our gross well information as of the dates indicated, inclusive of the Swallowtail Acquisition:

Diamondback Operated Third Party Operated Total
Horizontal wells turned to production (third quarter 2021)(1):
Gross wells 44 179 223
Net 100% royalty interest wells 1.8 1.3 3.1
Average percent net royalty interest 4.0  % 0.7  % 1.4  %
Horizontal producing well count (as of October 11, 2021):
Gross wells 1,295 4,282 5,577
Net 100% royalty interest wells 97.7 58.4 156.1
Average percent net royalty interest 7.5  % 1.4  % 2.8  %
Horizontal active development well count (as of October 11, 2021)(2):
Gross wells 103 467 570
Net 100% royalty interest wells 5.8 3.7 9.5
Average percent net royalty interest 5.7  % 0.8  % 1.7  %
Line of sight wells (as of October 11, 2021)(3):
Gross wells 107 385 492
Net 100% royalty interest wells 5.7 3.6 9.3
Average percent net royalty interest 5.3  % 0.9  % 1.9  %
(1) Average lateral length of 10,163.
(2) The total 570 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 492 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 volatility in oil prices.

20
Results of Operations

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

Three Months Ended September 30, Nine Months Ended September 30,
2021 2020 2021 2020
  (In thousands)
Operating income:
Oil income $ 100,154  $ 53,595  $ 272,450  $ 153,412 
Natural gas income 12,074  3,331  30,651  4,909 
Natural gas liquids income 15,421  5,658  34,518  13,536 
Royalty income 127,649  62,584  337,619  171,857 
Lease bonus income 223  40  1,032  1,685 
Other operating income 132  318  479  761 
Total operating income 128,004  62,942  339,130  174,303 
Costs and expenses:
Production and ad valorem taxes 8,625  5,049  23,426  14,306 
Depletion 25,366  24,780  74,230  72,204 
General and administrative expenses 1,735  1,811  6,118  6,160 
Total costs and expenses 35,726  31,640  103,774  92,670 
Income (loss) from operations 92,278  31,302  235,356  81,633 
Other income (expense):
Interest expense, net (8,328) (8,238) (24,161) (24,870)
Gain (loss) on derivative instruments, net (9,599) (5,084) (70,649) (47,469)
Gain (loss) on revaluation of investment —  (1,984) —  (8,661)
Other income, net —  188  77  1,111 
Total other expense, net (17,927) (15,118) (94,733) (79,889)
Income (loss) before income taxes 74,351  16,184  140,623  1,744 
Provision for (benefit from) income taxes 906  —  941  142,466 
Net income (loss) 73,445  16,184  139,682  (140,722)
Net income (loss) attributable to non-controlling interest 56,613  16,948  121,208  23,963 
Net income (loss) attributable to Viper Energy Partners LP $ 16,832  $ (764) $ 18,474  $ (164,685)

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

Three Months Ended September 30, Nine Months Ended September 30,
2021 2020 2021 2020
Production data:
Oil (MBbls) 1,480  1,456  4,378  4,359 
Natural gas (MMcf) 3,347  3,111  9,828  8,454 
Natural gas liquids (MBbls) 503  455  1,359  1,402 
Combined volumes (MBOE)(1)
2,541  2,430  7,375  7,169 
Average daily oil volumes (BO/d) 16,087  15,829  16,037  15,907 
Average daily combined volumes (BOE/d) 27,620  26,409  27,015  26,165 
Average sales prices:
Oil ($/Bbl) $ 67.67  $ 36.80  $ 62.23  $ 35.20 
Natural gas ($/Mcf) $ 3.61  $ 1.07  $ 3.12  $ 0.58 
Natural gas liquids ($/Bbl) $ 30.66  $ 12.44  $ 25.40  $ 9.66 
Combined ($/BOE)(2)
$ 50.24  $ 25.76  $ 45.78  $ 23.97 
Oil, hedged ($/Bbl)(3)
$ 50.57  $ 27.65  $ 48.26  $ 32.56 
Natural gas, hedged ($/Mcf)(3)
$ 3.61  $ 0.16  $ 3.12  $ (0.27)
Natural gas liquids ($/Bbl)(3)
$ 30.66  $ 12.44  $ 25.40  $ 9.66 
Combined price, hedged ($/BOE)(3)
$ 40.28  $ 19.11  $ 37.48  $ 21.36 
Average costs ($/BOE):
Production and ad valorem taxes $ 3.39  $ 2.08  $ 3.18  $ 2.00 
General and administrative - cash component(4)
0.59  0.63  0.70  0.73 
Total operating expense - cash $ 3.98  $ 2.71  $ 3.88  $ 2.73 
General and administrative - non-cash unit compensation expense $ 0.10  $ 0.11  $ 0.13  $ 0.13 
Interest expense, net $ 3.28  $ 3.39  $ 3.28  $ 3.47 
Depletion $ 9.98  $ 10.20  $ 10.07  $ 10.07 
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)Realized price net of all deducts for gathering, transportation and processing.
(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.

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Comparison of the Three and Nine Months Ended September 30, 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.

Royalty income increased $65.1 million and $165.8 million during the three and nine months ended September 30, 2021, respectively, compared to the same periods in 2020. Higher average prices contributed approximately $63.4 million and $164.7 million of the total increases, respectively, due largely to the recovery in oil prices, and to a lesser extent, natural gas and natural gas liquids prices from historic lows experienced in the 2020 periods as discussed in “—Overview.”

The 5% increase in production volumes during the third quarter of 2021 compared to the same period in 2020 contributed approximately $1.7 million of the total increase in royalty income. The 3% increase in production volumes during the nine months ended September 30, 2021 compared to the same period in 2020 contributed approximately $1.1 million of the total increase in royalty income. The increase in production for both the three and nine month periods is primarily attributable to new well additions between periods.

Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the three and nine months ended September 30, 2021 and 2020:

Three Months Ended September 30,
2021 2020
Amount
(In thousands) 		Per BOE Percentage of Royalty Income Amount
(In thousands) 		Per BOE Percentage of Royalty Income
Production taxes $ 6,750  $ 2.65  5.3  % $ 3,106  $ 1.28  5.0  %
Ad valorem taxes 1,875  0.74  1.5  1,943  0.80  3.1 
Total production and ad valorem taxes $ 8,625  $ 3.39  6.8  % $ 5,049  $ 2.08  8.1  %

Nine Months Ended September 30,
2021 2020
Amount
(In thousands) 		Per BOE Percentage of Royalty Income Amount
(In thousands) 		Per BOE Percentage of Royalty Income
Production taxes $ 17,264  $ 2.34  5.1  % $ 8,373  $ 1.17  4.9  %
Ad valorem taxes 6,162  0.84  1.8  5,933  0.83  3.4 
Total production and ad valorem taxes $ 23,426  $ 3.18  6.9  % $ 14,306  $ 2.00  8.3  %

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of royalty income for the three and nine months ended September 30, 2021 remained consistent with the three and nine months ended September 30, 2020. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. 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 interests remained relatively flat.

Depletion

Depletion expense and the depletion rate for the three and nine months ended September 30, 2021 compared to the same periods in 2020 were relatively flat as the increases in production during the 2021 periods were partially offset by a slight decrease in average depletion rates.

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Net Interest Expense

Net interest expense remained relatively flat for the three and nine months ended September 30, 2021 compared to the same periods in 2020. Net interest expense may increase in future periods as approximately $190.0 million of the Swallowtail Acquisition was funded with additional borrowings under the Operating Company’s revolving credit facility in October 2021 as discussed in “— Liquidity and Capital Resources—Indebtedness” above.

Derivative Instruments

The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:

Three Months Ended September 30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands)
Gain (loss) on derivative instruments $ (9,599) $ (5,084) $ (70,649) $ (47,469)
Net cash receipts (payments) on derivatives $ (25,306) $ (16,164) $ (61,188) $ (18,718)

We recorded losses on our derivative instruments for the three and nine months ended September 30, 2021 and 2020 primarily due to market prices being higher than the strike prices on our derivative contracts. 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.”

Gain (Loss) on Revaluation of Investment

We did not record a gain or loss on revaluation of investment for the three and nine months ended September 30, 2021, as we fully divested our equity interest in a limited partnership during 2020. We recorded losses on revaluation of investment of $2.0 million and $8.7 million for the three and nine months ended September 30, 2020 primarily due to recording the remaining investment at its fair value at September 30, 2020.

Provision for (Benefit from) Income Taxes

Income tax expense remained low at $0.9 million for the three months ended September 30, 2021, due to maintaining a valuation allowance against our deferred tax assets. We did not record an income tax benefit or expense for the three months ended September 30, 2020.

Income tax expense for the nine months ended September 30, 2021 was $0.9 million compared to $142.5 million for the nine months ended September 30, 2020. The change in our income tax provision was primarily due to the impact of recording a valuation allowance on our deferred tax assets during the first quarter of 2020. The total income tax provision for the nine months ended September 30, 2021 differed from amounts computed by applying the 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 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.

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We define Adjusted EBITDA as net income (loss) attributable to Viper Energy Partners LP plus net income (loss) attributable to non-controlling interest 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, (gain) loss on extinguishment of debt 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 (loss). 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 computation 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.

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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 September 30, Nine Months Ended September 30,
2021 2020 2021 2020
(In thousands)
Net income (loss) attributable to Viper Energy Partners LP $ 16,832  $ (764) $ 18,474  $ (164,685)
Net income (loss) attributable to non-controlling interest 56,613  16,948  121,208  23,963 
Net income (loss) 73,445  16,184  139,682  (140,722)
Interest expense, net 8,328  8,238  24,161  24,870 
Non-cash unit-based compensation expense 243  275  896  945 
Depletion 25,366  24,780  74,230  72,204 
(Gain) loss on revaluation of investment —  1,984  —  8,661 
Non-cash (gain) loss on derivative instruments (15,707) (11,080) 9,461  28,751 
(Gain) loss on extinguishment of debt —  20  —  6 
Provision for (benefit from) income taxes 906  —  941  142,466 
Consolidated Adjusted EBITDA 92,581  40,401  249,371  137,181 
Less: Adjusted EBITDA attributable to non-controlling interest(1)
54,269  23,113  145,685  78,492 
Adjusted EBITDA attributable to Viper Energy Partners LP $ 38,312  $ 17,288  $ 103,686  $ 58,689 
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
Income taxes payable $ (906) $ —  $ (941) $ — 
Debt service, contractual obligations, fixed charges and reserves (2,996) (3,297) (10,230) (9,941)
Cash paid for tax withholding on vested common units —  (1) (20) (384)
Distribution equivalent rights payments (62) (2) (141) (26)
Preferred distributions (45) (45) (135) (135)
Cash available for distribution to Viper Energy Partners LP unitholders $ 34,303  $ 13,943  $ 92,219  $ 48,203 
Common limited partner units outstanding 63,831  67,851  63,831  67,851 
Cash available for distribution per limited partner unit $ 0.54  $ 0.21  $ 1.44  $ 0.71 
Cash per unit approved for distribution $ 0.38  $ 0.10  $ 0.96  $ 0.23 
(1) Does not take into account special income allocation consideration.

Cash Distributions

The distribution for the third quarter of 2021 of $0.38 per common unit is payable on November 18, 2021 to common unitholders of record at the close of business on November 11, 2021. See Note 7—Unitholders' Equity and Distributions for further discussion of our distributions.

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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.

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 February 2021 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, commodity pricing environment and uncertain 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:

Nine Months Ended September 30,
2021 2020
(In thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities $ 199,672  $ 143,206 
Net cash provided by (used in) investing activities (6,728) (57,148)
Net cash provided by (used in) financing activities (140,525) (82,286)
Net increase (decrease) in cash and cash equivalents $ 52,419  $ 3,772 

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 as discussed in “—Results of Operations” above. 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 increase in net cash provided by operating activities during the nine months ended September 30, 2021 compared to the same period in 2020 was primarily driven by higher royalty income in 2021, which was largely offset by (i) changes in our working capital accounts, most notably through a reduction in cash collections on our accounts receivable in 2021 compared to 2020 due to the timing of our receipt of royalty income payments from our operators, (ii) an increase in cash paid for derivative settlements and (iii) an increase in production and ad valorem expenses due to the corresponding increase in royalty income.

Investing Activities

Net cash used in investing activities during the nine months ended September 30, 2021 and 2020, was primarily related to acquisitions of oil and natural gas interests.

Financing Activities

Net cash used in financing activities during the nine months ended September 30, 2021, was primarily related to the net borrowings of $8.0 million under the Operating Company’s revolving credit facility, distributions of $112.0 million to our unitholders and $33.6 million of repurchases of our common units during the third quarter of 2021 as discussed below.

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Net cash used in financing activities during the nine months ended September 30, 2020, was primarily related to distributions of $92.1 million to our unitholders and by repurchases of the Notes totaling $19.7 million, net of discounts during the second quarter of 2020. These reductions were partially offset by net proceeds from borrowing activity under the Operating Company’s revolving credit facility of $30.0 million.

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, of which approximately $57.6 million has been expended through September 30, 2021. During the nine months ended September 30, 2021, we repurchased approximately $33.6 million of common units under our repurchase program, which is authorized to extend through December 31, 2021. 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. Any common units under the repurchase program will be purchased opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events, such as the sale of assets. Any such repurchases may be made from time to time in open market or privately negotiated transactions in compliance with Rule 10b-18 under the Securities Exchange Act of 1934, as amended, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors.

Indebtedness

As of September 30, 2021, our indebtedness consists of $479.9 million in principal amount of Notes outstanding and $92.0 million in borrowings under the Operating Company’s revolving credit facility. We did not repurchase any Notes during the three and nine months ended September 30, 2021, but may do so opportunistically from time to time in future periods. 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 September 30, 2021, based on the Operating Company’s oil and natural gas reserves and other factors, although the Operating Company had elected a commitment amount of $500.0 million. The borrowing base of $580.0 million is expected to be reaffirmed by the lenders during the regularly scheduled (semi-annual) fall 2021 redetermination in November 2021. The next semi-annual redetermination is scheduled to occur in May 2022. As of September 30, 2021, there was $408.0 million available for future borrowings under the Operating Company’s revolving credit facility. During the three and nine months ended September 30, 2021, the weighted average interest rate on the Operating Company’s revolving credit facility was 1.98% and 2.14%, respectively. The revolving credit facility will mature on June 2, 2025.

On October 1, 2021, the Partnership and the Operating Company completed the Swallowtail Acquisition as discussed in Note 13—Subsequent Events—Swallowtail Acquisition. Approximately $190.0 million of the cash portion of this transaction was funded through borrowings under the Operating Company’s revolving credit facility, reducing the amount that remained available for future borrowings under this facility to $218.0 million as of October 1, 2021.

As of September 30, 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. Oil prices dropped sharply in early March 2020 and then continued to decline, briefly reaching negative levels. This was 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 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 demand and market prices for oil and natural gas have recently increased due to the rising energy use, easing of the COVID-19 pandemic and the improvements in the U.S. economic activity, we cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.

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 September 30, 2021, we had a net liability derivative position related to our commodity price derivatives of $36.1 million. Utilizing actual derivative contractual volumes under our contracts as of September 30, 2021, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position by $10.5 million to $46.6 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position by $10.0 million to $26.1 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. Volatility in commodity pricing environment and 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 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is the least of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. As of September 30, 2021, we had $92.0 million in outstanding borrowings. During the three and nine months ended September 30, 2021, the weighted average interest rate on the Operating Company’s revolving credit facility was 1.98% and 2.14%, respectively.

29
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 September 30, 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 September 30, 2021, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. In July 2021, we implemented an enterprise resource planning system covering various financial and accounting processes. As a result of this implementation, certain internal controls over financial reporting have been automated, modified or implemented to address the new environment associated with the implementation of this system. We believe we have maintained appropriate internal control over financial reporting during the implementation and believe this new system will strengthen our internal control system. However, there are inherent risks in implementing any new system, and we will continue to evaluate these control changes as part of our assessment of internal control over financial reporting throughout 2021. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended September 30, 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 September 30, 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)
July 1, 2021 - July 31, 2021 294,921 $ 17.41  294,921 $ 51,018 
August 1, 2021 - August 31, 2021 335,957 $ 17.71  335,957 $ 45,069 
September 1, 2021 - September 30, 2021 134,634 $ 19.74  134,634 $ 42,412 
Total 765,512 $ 17.95  765,512
(1)Includes common units repurchased from employees in order to satisfy tax withholding requirements, if any. Such units are cancelled and retired immediately upon repurchase.
(2)The average price paid per common unit includes any commissions paid to repurchase a common unit.
(3)In November 2020, the board of directors of our general partner 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 is subject to market conditions, applicable legal requirements, contractual obligations and other factors and 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 Number
Description
2.1
3.1
3.2
3.3
3.4
3.5
4.1
4.2
31.1*
31.2*
32.1**
101
The following financial information from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 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.
104
Cover 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: November 4, 2021 By: /s/ Travis D. Stice
Travis D. Stice
Chief Executive Officer
Date: November 4, 2021 By: /s/ Teresa L. Dick
Teresa L. Dick
Chief Financial Officer

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