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vnom-20220630

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 June 30, 2022


☐			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)

46-5001985

(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification Number)

500 West Texas Ave.

Suite 100

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 July 29, 2022, the registrant had outstanding 75,208,255 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 JUNE 30, 2022

TABLE OF CONTENTS


			Page
Glossary of Oil and Natural Gas Terms			ii
Glossary of Certain Other Terms			iii
Cautionary Statement Regarding Forward-Looking Statements			iv

PART I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)			1
Condensed Consolidated Balance Sheets			1
Condensed Consolidated Statements of Operations			2
Condensed Consolidated Statements of Changes to Unitholders’ Equity			3
Condensed Consolidated Statements of Cash Flows			5
Condensed Notes to Consolidated Financial Statements			6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			17

Item 3. Quantitative and Qualitative Disclosures about Market Risk			27

Item 4. Controls and Procedures			28

PART II. OTHER INFORMATION
Item 1. Legal Proceedings			29

Item 1A. Risk Factors			29

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			32

Item 6. Exhibits			33

Signatures			34

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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			Net mineral acres multiplied by the average lease royalty interest and other burdens.
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.

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GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this report:




ASU			Accounting Standards Update.
Adjusted EBITDA			Consolidated Adjusted EBITDA, a non-GAAP measure, generally equals its net income (loss) plus net income (loss) attributable to non-controlling interest before interest expense, net, non-cash unit-based compensation expense, depletion expense and non-cash (gain) loss on derivative instruments, (gain) loss on extinguishment of debt and provision for (benefit from) income taxes, which measure is used by management to more effectively evaluate the operating performance and determine distributable amounts for purposes of the distribution policy.
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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report are “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions. All statements, other than statements of historical fact, including statements regarding our: future performance; business strategy; future operations; estimates and projections of operating income, losses, costs and expenses, returns, cash flow, and financial position; production levels on properties in which we have mineral and royalty interests, developmental activity by other operators; reserve estimates and our ability to replace or increase reserves; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including Diamondback’s plans for developing our acreage and our cash distribution policy and repurchases of our common units and/or senior notes) are forward-looking statements. When used in this report, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to us 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 detailed under Part II. Item 1A. Risk Factors, our Annual Report on Form 10-K for the year ended December 31, 2021 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022 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.

Factors that could cause the outcomes to differ materially include (but are not limited to) the following:

•Changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities;

•the impact of public health crises, including epidemic or pandemic diseases such as the COVID-19 pandemic, and any related company or government policies or actions;

•actions taken by the members of OPEC and Russia affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;

•changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates, inflation rates and concerns over a potential recession;

•regional supply and demand factors, including delays, curtailment delays or interruptions of production on our mineral and royalty acreage, or governmental orders, rules or regulations that impose production limits on such acreage;

•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;

•transition risks relating to climate change;

•restrictions on the use of water, including limits on the use of produced water by our operators and a moratorium on new produced water well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin;

•significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges;

•changes in U.S. energy, environmental, monetary and trade policies;

•conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development by our operators and environmental and social responsibility projects undertaken by Diamondback and our other operators;

•changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services impacting our operators;

•changes in safety, health, environmental, tax, and other regulations or requirements impacting us or our operators (including those addressing air emissions, water management, or the impact of global climate change);

•security threats, including cybersecurity threats and disruptions to our business from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business;

•lack of, or disruption in, access to adequate and reliable transportation, processing, storage, and other facilities impacting our operators;

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•severe weather conditions;

•acts of war or terrorist acts and the governmental or military response thereto;

•changes in the financial strength of counterparties to the credit agreement and hedging contracts of our operating subsidiary;

•changes in our credit rating; and

•other risks and factors disclosed in this report.

In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, new risks emerge from time to time. We cannot 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 anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this report. 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 applicable law.

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PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Viper Energy Partners LP

Condensed Consolidated Balance Sheets

(Unaudited)


	June 30,		December 31,
	2022		2021
	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	4,312	$	39,448

Royalty income receivable (net of allowance for credit losses)	122,444		68,568
Royalty income receivable—related party	10,589		2,144
Derivative instruments	1,010		—
Other current assets	1,502		989
Total current assets	139,857		111,149
Property:
Oil and natural gas interests, full cost method of accounting ($1,409,092 and $1,640,172 excluded from depletion at June 30, 2022 and December 31, 2021, respectively)	3,482,392		3,513,590
Land	5,688		5,688
Accumulated depletion and impairment	(658,536)		(599,163)
Property, net	2,829,544		2,920,115

Derivative instruments	1,439		—

Other assets	1,145		2,757
Total assets	$	2,971,985	$	3,034,021
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	9	$	69

Accrued liabilities	14,989		20,509
Derivative instruments	9,085		3,417
Income taxes payable	2,759		471
Total current liabilities	26,842		24,466
Long-term debt, net	674,383		776,727


Total liabilities	701,225		801,193
Commitments and contingencies (Note 12)

Unitholders’ equity:
General Partner	689		729
Common units (75,946,203 units issued and outstanding as of June 30, 2022 and 78,546,403 units issued and outstanding as of December 31, 2021)	733,998		813,161
Class B units (90,709,946 units issued and outstanding as of June 30, 2022 and December 31, 2021)	881		931
Total Viper Energy Partners LP unitholders’ equity	735,568		814,821
Non-controlling interest	1,535,192		1,418,007
Total equity	2,270,760		2,232,828
Total liabilities and unitholders’ equity	$	2,971,985	$	3,034,021

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Operations

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands, except per unit amounts)
Operating income:
Royalty income	$	238,830	$	113,458	$	431,919	$	209,970
Lease bonus income	329		484		9,011		809

Other operating income	163		208		295		347
Total operating income	239,322		114,150		441,225		211,126
Costs and expenses:
Production and ad valorem taxes	16,039		8,152		29,909		14,801

Depletion	31,962		23,978		59,373		48,864

General and administrative expenses	1,880		2,162		3,833		4,383

Total costs and expenses	49,881		34,292		93,115		68,048
Income (loss) from operations	189,441		79,858		348,110		143,078
Other income (expense):
Interest expense, net	(9,782)		(7,973)		(19,427)		(15,833)


Gain (loss) on derivative instruments, net	(1,889)		(29,546)		(20,248)		(61,050)

Other income, net	32		39		38		77
Total other expense, net	(11,639)		(37,480)		(39,637)		(76,806)
Income (loss) before income taxes	177,802		42,378		308,473		66,272
Provision for (benefit from) income taxes	6,182		—		8,812		35
Net income (loss)	171,620		42,378		299,661		66,237
Net income (loss) attributable to non-controlling interest	137,598		37,716		249,034		64,595
Net income (loss) attributable to Viper Energy Partners LP	$	34,022	$	4,662	$	50,627	$	1,642

Net income (loss) attributable to common limited partner units:
Basic	$	0.44	$	0.07	$	0.66	$	0.03
Diluted	$	0.44	$	0.07	$	0.66	$	0.03
Weighted average number of common limited partner units outstanding:
Basic	76,620		64,672		76,861		65,014
Diluted	76,729		64,795		76,978		65,151

See accompanying notes to condensed consolidated financial statements.

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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, 2021	78,546	$	813,161	90,710	$	931	$	729	$	1,418,007	$	2,232,828







Unit-based compensation	—	284		—	—		—		—		284




Distribution equivalent rights payments	—	(64)		—	—		—		—		(64)
Distributions to public	—	(35,830)		—	—		—		—		(35,830)
Distributions to Diamondback	—	(344)		—	(25)		—		(42,634)		(43,003)
Distributions to General Partner	—	—		—	—		(20)		—		(20)
Change in ownership of consolidated subsidiaries, net	—	14,195			—		—		(14,195)		—

Repurchased units as part of unit buyback	(1,580)	(39,260)		—	—		—		—		(39,260)
Net income (loss)	—	16,605		—	—		—		111,436		128,041
Balance at March 31, 2022	76,966	768,747		90,710	906		709		1,472,614		2,242,976




Unit-based compensation	—	335		—	—		—		—		335

Distribution equivalent rights payments	—	(113)		—	—		—		—		(113)



Distributions to public	—	(51,077)		—	—		—		—		(51,077)
Distributions to Diamondback	—	(490)		—	(25)		—		(63,497)		(64,012)
Distributions to General Partner	—	—		—	—		(20)		—		(20)
Change in ownership of consolidated subsidiaries, net	—	11,523			—		—		(11,523)		—

Repurchased units as part of unit buyback	(1,020)	(28,949)		—	—		—		—		(28,949)
Net income (loss)	—	34,022		—	—		—		137,598		171,620
Balance at June 30, 2022	75,946	$	733,998	90,710	$	881	$	689	$	1,535,192	$	2,270,760

See accompanying notes to condensed consolidated financial statements.

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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, 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, net	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

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2022		2021
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	299,661	$	66,237
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depletion	59,373		48,864

(Gain) loss on derivative instruments, net	20,248		61,050
Net cash receipts (payments) on derivatives	(17,029)		(35,882)






Other	2,893		1,992
Changes in operating assets and liabilities:

Royalty income receivable	(53,876)		(9,801)
Royalty income receivable—related party	(8,445)		(1,681)


Accounts payable and accrued liabilities	(5,580)		(1,107)




Other	1,775		8
Net cash provided by (used in) operating activities	299,020		129,680
Cash flows from investing activities:

Acquisitions of oil and natural gas interests	1,862		(819)



Proceeds from sale of assets	29,336		—


Net cash provided by (used in) investing activities	31,198		(819)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	144,000		25,000
Repayment on credit facility	(198,000)		(47,000)

Repayment of senior notes	(48,963)		—








Repurchased units as part of unit buyback	(68,209)		(19,822)
Distributions to public	(87,084)		(25,107)
Distributions to Diamondback	(107,015)		(35,712)
Other	(83)		(2,919)
Net cash provided by (used in) financing activities	(365,354)		(105,560)
Net increase (decrease) in cash and cash equivalents	(35,136)		23,301
Cash, cash equivalents and restricted cash at beginning of period	39,448		19,121
Cash, cash equivalents and restricted cash at end of period	$	4,312	$	42,422

See accompanying notes to condensed consolidated financial statements.

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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 June 30, 2022, Viper Energy Partners GP LLC (the “General Partner”) held a 100% general partner interest in the Partnership and Diamondback Energy, Inc. (“Diamondback”) beneficially owned approximately 55% 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, 2021, 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, the effects of COVID-19, the war in Ukraine and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets continued to contribute to economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts.

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

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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

Related Party Transactions

During the six months ended June 30, 2022, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $6.3 million of lease bonus income related to certain leases acquired in the Swallowtail Acquisition.

There were no other significant related party transactions for the three months ended June 30, 2022 and the three and six months ended June 30, 2021.

Accrued Liabilities

Accrued liabilities consist of the following:


	June 30,		December 31,
	2022		2021
	(In thousands)
Interest payable	$	3,875	$	4,430
Ad valorem taxes payable	7,946		6,201
Derivatives instruments payable	1,644		8,879
Other	1,524		999
Total accrued liabilities	$	14,989	$	20,509

Recent Accounting Pronouncements

Accounting Pronouncements Not Yet Adopted

The Partnership considers the applicability and impact of all ASUs. There are no recent accounting pronouncements not yet adopted that are expected to have a material effect on the Partnership upon adoption, as applicable.

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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands)
Oil income	$	191,195	$	93,952	$	346,246	$	172,296
Natural gas income	23,793		9,533		38,983		18,577
Natural gas liquids income	23,842		9,973		46,690		19,097
Total royalty income	$	238,830	$	113,458	$	431,919	$	209,970

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4. ACQUISITIONS AND DIVESTITURES

2022 Activity

Divestiture

In the first quarter of 2022, the Partnership divested 325 net royalty acres of third party operated acreage located entirely in Upton and Reagan counties in the Midland Basin for an aggregate sales price of $29.3 million, subject to post-closing adjustments.

The Partnership had no other significant acquisition or divestiture activity during the six months ended June 30, 2022.

2021 Activity

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 approximately 15.25 million common units and approximately $225.3 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 as of December 31, 2021. 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 in October 2021. The cash portion of this transaction was funded through a combination of cash on hand and approximately $190.0 million of borrowings under the Operating Company’s revolving credit facility.

Other 2021 Acquisitions

Additionally during the year ended December 31, 2021, the Partnership acquired, from unrelated third party sellers, mineral and royalty interests representing 1,277 gross (392 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $55.1 million, after 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:


	June 30,		December 31,
	2022		2021
	(In thousands)
Oil and natural gas interests:
Subject to depletion	$	2,073,300	$	1,873,418
Not subject to depletion	1,409,092		1,640,172
Gross oil and natural gas interests	3,482,392		3,513,590
Accumulated depletion and impairment	(658,536)		(599,163)
Oil and natural gas interests, net	2,823,856		2,914,427
Land	5,688		5,688
Property, net of accumulated depletion and impairment	$	2,829,544	$	2,920,115

As of June 30, 2022 and December 31, 2021, the Partnership had mineral and royalty interests representing 26,718 and 27,027 net royalty acres, respectively.

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No impairment expense was recorded on the Partnership’s oil and natural gas interests for the three and six months ended June 30, 2022 and 2021 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 may have material write-downs in subsequent quarters.

6. DEBT

Long-term debt consisted of the following as of the dates indicated:


	June 30,		December 31,
	2022		2021
	(In thousands)
5.375% senior unsecured notes due 2027	$	430,350	$	479,938
Revolving credit facility	250,000		304,000
Unamortized debt issuance costs	(1,441)		(1,757)
Unamortized discount	(4,526)		(5,454)
Total long-term debt	$	674,383	$	776,727

Repurchases of Notes

During the second quarter of 2022, the Partnership repurchased an aggregate $49.6 million principal amount of the outstanding Notes for total cash consideration of $49.0 million, which resulted in an immaterial loss on extinguishment of debt during the second quarter of 2022. The Partnership funded the debt repurchases through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility.

The Operating Company’s Revolving Credit Facility

The Operating Company’s credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base of $580.0 million based on the Operating Company’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November. As of June 30, 2022, the Operating Company had elected a commitment amount of $500.0 million, with $250.0 million of outstanding borrowings and $250.0 million available for future borrowings under the Operating Company’s revolving credit facility. During the three and six months ended June 30, 2022 and 2021, the weighted average interest rates on the Operating Company’s revolving credit facility were 3.20%, 2.88%, 1.93% and 1.90%, respectively. The revolving credit facility will mature on June 2, 2025.

As of June 30, 2022, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement.

7. UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has General Partner and limited partner units. At June 30, 2022, the Partnership had a total of 75,946,203 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 55% of the Partnership’s total units outstanding. At June 30, 2022, Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 54% 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).

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Common Unit Repurchase Program

The board of directors of the Partnership’s General Partner has approved a common unit repurchase program to acquire up to $250.0 million of the Partnership’s outstanding common units over an indefinite period of time. The Partnership intends to purchase common units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of the Partnership’s General Partner at any time. During the three and six months ended June 30, 2022 and 2021, the Partnership repurchased approximately $28.9 million, $68.2 million, $6.8 million and $19.8 million of common units under the repurchase program, respectively. Repurchases for the six months ended June 30, 2022 include approximately $37.3 million for the repurchase of 1.5 million common units from a significant unitholder in a privately negotiated transaction in the first quarter of 2022. As of June 30, 2022, $111.8 million remains available for use to repurchase common units under the repurchase program. See also Note 13—Subsequent Events discussing the increase in the repurchase program authorization approved on July 26, 2022.

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 or a portion 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 cash available for distribution by the Operating Company, a non-GAAP measure, generally equals the Partnership’s consolidated Adjusted EBITDA for the applicable 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 cash available for distribution for each quarter generally equals the Partnership’s proportional share of the cash distributed by the Operating Company for the quarter, less cash needed by the Partnership for the payment of income taxes, if any, and the preferred distribution. The percentage of cash available for distribution 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 2021	$	0.47	$	42,634	$	36,238	February 16, 2022	March 4, 2022	March 11, 2022
Q1 2022	$	0.67	$	63,497	$	51,680	April 27, 2022	May 12, 2022	May 19, 2022

(1)Includes amounts paid to Diamondback for the 731,500 common units beneficially owned by Diamondback and distribution equivalent rights payments.

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.

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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, but do not impact earnings. The following table summarizes the changes in common unitholder equity due to changes in ownership interest during the period:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands)
Net income (loss) attributable to the Partnership	$	34,022	$	4,662	$	50,627	$	1,642

Change in ownership of consolidated subsidiaries	11,523		1,614		25,718		4,301




Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest	$	45,545	$	6,276	$	76,345	$	5,943

Allocation of Net Income

The Partnership, as managing member of the Operating Company, has entered into an agreement, as amended on December 28, 2021, 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 2022. 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 six months ended June 30, 2022 and 2021, 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 Distributions.

Basic and diluted earnings per common unit is calculated using the two-class method. The two class method is an earnings allocation proportional to the respective ownership among holders of common units and participating securities. 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.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(In thousands, except per unit amounts)
Net income (loss) attributable to the period	$	34,022	$	4,662	$	50,627	$	1,642
Less: net income (loss) allocated to participating securities(1)	(113)		(55)		(177)		(79)
Net income (loss) attributable to common unitholders	$	33,909	$	4,607	$	50,450	$	1,563


Weighted average common units outstanding:
Basic weighted average common units outstanding	76,620		64,672		76,861		65,014
Effect of dilutive securities:
Potential common units issuable(2)	109		123		117		137
Diluted weighted average common units outstanding	76,729		64,795		76,978		65,151
Net income (loss) per common unit, basic	$	0.44	$	0.07	$	0.66	$	0.03
Net income (loss) per common unit, diluted	$	0.44	$	0.07	$	0.66	$	0.03

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

(2) For the three and six months ended June 30, 2022, there were no potential common units excluded from the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive. For the three and six months ended June 30, 2021, 39 and 4,974, respectively, potential common units were excluded 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.

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 June 30,						Six Months Ended June 30,
	2022			2021			2022			2021
	(In thousands, except for tax rate)
Provision for (benefit from) income taxes	$	6,182		$	—		$	8,812		$	35
Effective tax rate	3.5		%	—		%	2.9		%	0.1		%

The Partnership’s effective income tax rates for the three and six months ended June 30, 2022 and 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of maintaining a valuation allowance on the Partnership’s deferred tax assets.

As of June 30, 2022 and 2021, 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.”

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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 June 30, 2022, the Partnership has costless collars, put options and basis swaps 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 Operating Company; therefore, the Partnership is not required to post any collateral. The Partnership’s counterparties have been determined to have an acceptable credit risk; therefore, the Partnership does not require collateral from its counterparties.

As of June 30, 2022, 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 Floor Price

Weighted Average Ceiling Price

Strike Price

OIL

Jul. - Sep.

2022

Collars

4,000

WTI Cushing

$—

$45.00

$92.65

$—

Oct. - Dec.

2022

Collars

4,000

WTI Cushing

$—

$50.00

$128.01

$—

Jul. - Sep.

2022

Puts(1)