UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended ~~March 31,~~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 ~~1200~~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 ~~April~~July 29, 2022, the registrant had outstanding ~~76,966,203~~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 ~~MARCH 31,~~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			45
Condensed Notes to Consolidated Financial Statements			56

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			1617

Item 3. Quantitative and Qualitative Disclosures about Market Risk			2627

Item 4. Controls and Procedures			2728

PART II. OTHER INFORMATION
Item 1. Legal Proceedings			2829

Item 1A. Risk Factors			2829

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			2932

Item 6. Exhibits			3033

Signatures			3134

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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. Ri skRisk Factors ~~and~~, 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 ~~inflation rates;~~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;

•~~severe weather conditions;~~

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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 ~~our~~ ~~Annual Report on Form 10–K~~ ~~for the year ended December 31, 2021.~~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)

March 31, December 31,
2022 2021
(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents $ 33,066 $ 39,448
Royalty income receivable (net of allowance for credit losses) 98,500 68,568
Royalty income receivable—related party 4,192 2,144
Other current assets 944 989
Total current assets 136,702 111,149
Property:
Oil and natural gas interests, full cost method of accounting ($1,602,581 and $1,640,172 excluded from depletion at March 31, 2022 and December 31, 2021, respectively) 3,481,633 3,513,590
Land 5,688 5,688
Accumulated depletion and impairment (626,574) (599,163)
Property, net 2,860,747 2,920,115
Derivative instruments 1,705 —
Other assets 1,931 2,757
Total assets $ 3,001,085 $ 3,034,021
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable $ 14 $ 69
Accrued liabilities 23,873 20,980
Derivative instruments 13,217 3,417
Total current liabilities 37,104 24,466
Long-term debt, net 721,005 776,727
Total liabilities 758,109 801,193
Commitments and contingencies (Note 12) 0 0
Unitholders’ equity:
General Partner 709 729
Common units (76,966,203 units issued and outstanding as of March 31, 2022 and 78,546,403 units issued and outstanding as of December 31, 2021) 768,747 813,161
Class B units (90,709,946 units issued and outstanding as of March 31, 2022 and December 31, 2021) 906 931
Total Viper Energy Partners LP unitholders’ equity 770,362 814,821
Non-controlling interest 1,472,614 1,418,007
Total equity 2,242,976 2,232,828
Total liabilities and unitholders’ equity $ 3,001,085 $ 3,034,021


	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)	0		0

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 March 31,
2022 2021
(In thousands, except per unit amounts)
Operating income:
Royalty income $ 193,089 $ 96,512
Lease bonus income 8,682 325
Other operating income 132 139
Total operating income 201,903 96,976
Costs and expenses:
Production and ad valorem taxes 13,870 6,649
Depletion 27,411 24,886
General and administrative expenses 1,953 2,221
Total costs and expenses 43,234 33,756
Income (loss) from operations 158,669 63,220
Other income (expense):
Interest expense, net (9,645) (7,860)
Gain (loss) on derivative instruments, net (18,359) (31,504)
Other income, net 6 38
Total other expense, net (27,998) (39,326)
Income (loss) before income taxes 130,671 23,894
Provision for (benefit from) income taxes 2,630 35
Net income (loss) 128,041 23,859
Net income (loss) attributable to non-controlling interest 111,436 26,879
Net income (loss) attributable to Viper Energy Partners LP $ 16,605 $ (3,020)
Net income (loss) attributable to common limited partner units:
Basic $ 0.22 $ (0.05)
Diluted $ 0.22 $ (0.05)
Weighted average number of common limited partner units outstanding:
Basic 77,106 65,360
Diluted 77,214 65,360


	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										Limited Partners													General Partner		Non-Controlling Interest
		Common			Class B			Amount				Amount										Common							Class B						Amount		Amount
		Units	Amount		Units	Amount										Total			Units					Amount			Units			Amount									Total
		(In thousands)																	(In thousands)
Balance at December 31, 2021	Balance at December 31, 2021	78,546	$	813,161	90,710	$	931			$	729			$	1,418,007					$	2,232,828		Balance at December 31, 2021	78,546			$	813,161		90,710			$	931			$	729		$	1,418,007			$	2,232,828

Unit-based compensation	Unit-based compensation	—	284		—	—		—				—					284			Unit-based compensation		—			284				—		—				—		—					284

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

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

Unit-based compensation																				Unit-based compensation		—			335				—		—				—		—					335

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

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

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

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

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of ~~Cash Flows~~Changes to Unitholders' Equity - (Continued)

(Unaudited)

Three Months Ended March 31,
2022 2021
(In thousands)
Cash flows from operating activities:
Net income (loss) $ 128,041 $ 23,859
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion 27,411 24,886
(Gain) loss on derivative instruments, net 18,359 31,504
Net cash receipts (payments) on derivatives (10,264) (14,942)
Other 1,388 901
Changes in operating assets and liabilities:
Royalty income receivable (29,932) (9,581)
Royalty income receivable—related party (2,048) (3,523)
Accounts payable and accrued liabilities 2,838 1,395
Other 45 160
Net cash provided by (used in) operating activities 135,838 54,659
Cash flows from investing activities:
Acquisitions of oil and natural gas interests 2,621 (74)
Proceeds from sale of assets 29,336 —
Net cash provided by (used in) investing activities 31,957 (74)
Cash flows from financing activities:
Proceeds from borrowings under credit facility 44,000 —
Repayment on credit facility (100,000) (27,000)
Debt issuance costs — (10)
Repurchased units as part of unit buyback (39,260) (13,043)
Distributions to public (35,894) (9,060)
Distributions to Diamondback (43,003) (12,826)
Other (20) (40)
Net cash provided by (used in) financing activities (174,177) (61,979)
Net increase (decrease) in cash and cash equivalents (6,382) (7,394)
Cash, cash equivalents and restricted cash at beginning of period 39,448 19,121
Cash, cash equivalents and restricted cash at end of period $ 33,066 $ 11,727


	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 ~~March 31,~~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% oof th~~f the~~e Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner.

Basis of Presentation

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

These condensed consolidated financial statements have been prepared by the Partnership without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This report should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 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 ~~Russian-Ukrainian military conflict~~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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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 ~~three~~six months ended ~~March 31,~~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 ~~March 31,~~June 30, 2022 orand the three and six months ended June 30, 2021.

Accrued Liabilities

Accrued liabilities consist of the following:


		March 31,		December 31,			June 30,		December 31,
		2022		2021			2022		2021
		(In thousands)					(In thousands)
Interest payable	Interest payable	$	10,787	$	4,430	Interest payable	$	3,875	$	4,430
Ad valorem taxes payable	Ad valorem taxes payable	3,974		6,201		Ad valorem taxes payable	7,946		6,201
Derivatives instruments payable	Derivatives instruments payable	3,117		8,879		Derivatives instruments payable	1,644		8,879
Income tax payable		3,100		—
Other	Other	2,895		1,470		Other	1,524		999
Total accrued liabilities	Total accrued liabilities	$	23,873	$	20,980	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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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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

Three Months Ended March 31,
2022 2021
(In thousands)
Oil income $ 155,051 $ 78,344
Natural gas income 15,190 9,044
Natural gas liquids income 22,848 9,124
Total royalty income $ 193,089 $ 96,512

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.~~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.~~transaction in October 2021. The cash portion of this transaction was funded through a combination of cash on hand and approximately of $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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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

~~5. OIL AND NATURAL GAS INTERESTS~~

~~Oil and natural gas interests include the following:~~

March 31, December 31,
2022 2021
(In thousands)
Oil and natural gas interests:
Subject to depletion $ 1,879,052 $ 1,873,418
Not subject to depletion 1,602,581 1,640,172
Gross oil and natural gas interests 3,481,633 3,513,590
Accumulated depletion and impairment (626,574) (599,163)
Oil and natural gas interests, net 2,855,059 2,914,427
Land 5,688 5,688
Property, net of accumulated depletion and impairment $ 2,860,747 $ 2,920,115

~~As of March 31, 2022 and December 31, 2021, the Partnership had mineral and royalty interests representing 26,708 and 27,027 net royalty acres, respectively.~~

No impairment expense was recorded on the Partnership’s oil and natural gas interests for the three and six months ended ~~March 31,~~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:


		March 31,		December 31,			June 30,		December 31,
		2022		2021			2022		2021
		(In thousands)					(In thousands)
5.375% senior unsecured notes due 2027	5.375% senior unsecured notes due 2027	$	479,938	$	479,938	5.375% senior unsecured notes due 2027	$	430,350	$	479,938
Revolving credit facility	Revolving credit facility	248,000		304,000		Revolving credit facility	250,000		304,000
Unamortized debt issuance costs	Unamortized debt issuance costs	(1,681)		(1,757)		Unamortized debt issuance costs	(1,441)		(1,757)
Unamortized discount	Unamortized discount	(5,252)		(5,454)		Unamortized discount	(4,526)		(5,454)
Total long-term debt	Total long-term debt	$	721,005	$	776,727	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 ~~March 31,~~June 30, 2022, the Operating Company had elected a commitment amount of $500.0 million, with ~~$248.0~~$250.0 million of outstanding borrowings and ~~$252.0~~$250.0 million available for future borrowings under the Operating Company’s revolving credit facility. During the three and six months ended ~~March 31,~~June 30, 2022 and 2021, the weighted average interest ~~rate~~rates on the Operating Company’s revolving credit facility ~~was~~were ~~2.58%~~3.20%, 2.88%, 1.93% and ~~1.88%~~1.90%, respectively. The revolving credit facility will mature on June 2, 2025.

As of ~~March 31,~~June 30, 2022, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement.

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~~Condensed Notes to Consolidated Financial Statements - (Continued)~~

~~(Unaudited)~~

7. UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has General Partner and limited partner units. At ~~March 31,~~June 30, 2022, the Partnership had a total of ~~76,966,203~~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% ofof the Partnership’s total units outstanding. At ~~March 31,~~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, 1 Operating Company unit and 1 Partnership Class B unit, together, will be exchangeable for 1 Partnership common unit).

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 $~~150.0~~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 ~~March 31,~~June 30, 2022 and 2021, the Partnership repurchased approximately ~~$39.3~~$28.9 million, $68.2 million, $6.8 million and ~~$13.0~~$19.8 million of common units under the repurchase program, respectively. Repurchases infor the ~~first quarter of~~six months ended June 30, 2022 include approximately $37.3 million for the repurchase of 1.5 million common units from ~~an affiliate~~a significant unitholder in a privately negotiated ~~transaction.~~transaction in the first quarter of 2022. As of ~~March 31,~~June 30, 2022, ~~$40.7~~$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 ~~April 27,~~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’s available cash~~Company, a non-GAAP measure, generally equals ~~its~~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 ~~cash~~for distribution for each quarter generally equals the Partnership’s proportional share of the cash distributed by the Operating ~~Company’s available cash~~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 ~~cash distributed~~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

Percentage of Operating Company Available Cash Distributed

Operating Company Distributions to Diamondback

Common Unitholders(1)

Declaration Date

Unitholder Record Date

Payment Date

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

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.

910

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 March 31,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021			2022		2021		2022		2021
		(In thousands)					(In thousands)
Net income (loss) attributable to the Partnership	Net income (loss) attributable to the Partnership	$	16,605	$	(3,020)	Net income (loss) attributable to the Partnership	$	34,022	$	4,662	$	50,627	$	1,642

Change in ownership of consolidated subsidiaries	Change in ownership of consolidated subsidiaries	14,195		2,687		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	Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest	$	30,800	$	(333)	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 ~~March 31,~~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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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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


		Three Months Ended March 31,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021					2022		2021		2022		2021
		(In thousands, except per unit amounts)				(In thousands, except per unit amounts)
Net income (loss) attributable to the period	Net income (loss) attributable to the period	$	16,605	$	(3,020)			Net income (loss) attributable to the period	$	34,022	$	4,662	$	50,627	$	1,642
Less: net income (loss) allocated to participating securities(1)	Less: net income (loss) allocated to participating securities(1)	(64)		(24)				Less: net income (loss) allocated to participating securities(1)	(113)		(55)		(177)		(79)
Net income (loss) attributable to common unitholders	Net income (loss) attributable to common unitholders	$	16,541	$	(3,044)			Net income (loss) attributable to common unitholders	$	33,909	$	4,607	$	50,450	$	1,563

Weighted average common units outstanding:	Weighted average common units outstanding:							Weighted average common units outstanding:
Basic weighted average common units outstanding	Basic weighted average common units outstanding	77,106		65,360				Basic weighted average common units outstanding	76,620		64,672		76,861		65,014
Effect of dilutive securities:	Effect of dilutive securities:							Effect of dilutive securities:
Potential common units issuable(2)	Potential common units issuable(2)	108		—				Potential common units issuable(2)	109		123		117		137
Diluted weighted average common units outstanding	Diluted weighted average common units outstanding	77,214		65,360				Diluted weighted average common units outstanding	76,729		64,795		76,978		65,151
Net income (loss) per common unit, basic	Net income (loss) per common unit, basic	$	0.22	$	(0.05)			Net income (loss) per common unit, basic	$	0.44	$	0.07	$	0.66	$	0.03
Net income (loss) per common unit, diluted	Net income (loss) per common unit, diluted	$	0.22	$	(0.05)			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 ~~March 31,~~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, ~~112,436~~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 March 31,							Three Months Ended June 30,					Six Months Ended June 30,
		2022			2021						2022			2021			2022			2021
		(In thousands, except for tax rate)						(In thousands, except for tax rate)
Provision for (benefit from) income taxes	Provision for (benefit from) income taxes	$	2,630		$	35				Provision for (benefit from) income taxes	$	6,182		$	—		$	8,812		$	35
Effective tax rate	Effective tax rate	2.0		%	0.1		%			Effective tax rate	3.5		%	—		%	2.9		%	0.1		%

The Partnership’s effective income tax rates for the three and six months ended ~~March 31,~~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 ~~March 31,~~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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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 ~~March 31,~~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 ~~guarantor subsidiaries;~~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 ~~March 31,~~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						Swaps	Collars		Puts
Settlement Month	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	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	OIL									OIL

Jul. - Sep.	Jul. - Sep.	2022	Collars	4,000	WTI Cushing	$—	$45.00	$92.65	$—	Jul. - Sep.	2022	Collars	4,000	WTI Cushing	$—	$45.00	$92.65	$—

Oct. - Dec.	Oct. - Dec.	2022	Collars	4,000	WTI Cushing	$—	$50.00	$128.01	$—	Oct. - Dec.	2022	Collars	4,000	WTI Cushing	$—	$50.00	$128.01	$—

Apr. - Jun.		2022	Puts(1)	10,000	WTI Cushing	$—	$—		$47.50
Jul. - Sep.										Jul. - Sep.	2022	Puts(1)	8,000	WTI Cushing	$—	$—		$47.50
Oct. - Dec.										Oct. - Dec.	2022	Puts(2)	8,000	WTI Cushing	$—	$—		$55.00
Jan. - Mar.										Jan. - Mar.	2023	Puts(3)	6,000	WTI Cushing	$—	$—		$	55.00
NATURAL GAS										NATURAL GAS
Jul. - Dec.	Jul. - Dec.	2022	Puts(2)	8,000	WTI Cushing	$—	$—		$47.50	Jul. - Dec.	2022	Collars	20,000	Henry Hub	$—	$2.50	$4.62	$—
NATURAL GAS
Apr. - Dec.		2022	Collars	20,000	Henry Hub	$—	$2.50	$4.62	$—
Jan. - Dec.	Jan. - Dec.	2023	Basis Swap(3)	10,000	Waha Hub	$(1.02)	$—		$—	Jan. - Dec.	2023	Basis Swap(4)	20,000	Waha Hub	$(1.36)	$—		$—

(1) Includes a deferred premium at a weighted average price of ~~$1.49/~~$1.52/Bbl.

(2) Includes a deferred premium at a weighted average price of ~~$1.52/~~$1.54/Bbl.

(3) Includes a deferred premium at a weighted average price of $1.87/Bbl.

(4) The Partnership has fixed price basis swaps for the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 March 31,					Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021					2022		2021		2022		2021
		(In thousands)				(In thousands)
Gain (loss) on derivative instruments	Gain (loss) on derivative instruments	$	(18,359)	$	(31,504)			Gain (loss) on derivative instruments	$	(1,889)	$	(29,546)	$	(20,248)	$	(61,050)
Net cash receipts (payments) on derivatives(1)	Net cash receipts (payments) on derivatives(1)	$	(10,264)	$	(14,942)			Net cash receipts (payments) on derivatives(1)	$	(6,765)	$	(20,940)	$	(17,029)	$	(35,882)

(1)The ~~three~~six months ended ~~March 31,~~June 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $4.2 million.

11. FAIR VALUE MEASUREMENTS

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

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Partnership’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Partnership uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Partnership’s derivative instruments. The fair values of the Partnership’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties and (iv) the resulting net amounts presented in the Partnership’s condensed consolidated balance sheets as of ~~March 31,~~June 30, 2022 and December 31, 2021. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.


		As of March 31, 2022													As of June 30, 2022
		Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet			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)													(In thousands)
Assets:	Assets:													Assets:
Current:	Current:													Current:
Derivative instruments	Derivative instruments	$	—	$	1,295	$	—	$	1,295	$	(1,295)	$	—	Derivative instruments	$	—	$	4,796	$	—	$	4,796	$	(3,786)	$	1,010
Non-current:	Non-current:													Non-current:

Derivative instruments	Derivative instruments	$	—	$	1,823	$	—	$	1,823	$	(118)	$	1,705	Derivative instruments	$	—	$	1,674	$	—	$	1,674	$	(235)	$	1,439
Liabilities:	Liabilities:													Liabilities:
Current:	Current:													Current:
Derivative instruments	Derivative instruments	$	—	$	14,512	$	—	$	14,512	$	(1,295)	$	13,217	Derivative instruments	$	—	$	12,871	$	—	$	12,871	$	(3,786)	$	9,085
Non-current:	Non-current:													Non-current:
Derivative instruments	Derivative instruments	$	—	$	118	$	—	$	118	$	(118)	$	—	Derivative instruments	$	—	$	235	$	—	$	235	$	(235)	$	—


	As of December 31, 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	$	—	$	1,921	$	—	$	1,921	$	(1,921)	$	—



Liabilities:
Current:
Derivative instruments	$	—	$	5,338	$	—	$	5,338	$	(1,921)	$	3,417

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:


		March 31, 2022				December 31, 2021					June 30, 2022				December 31, 2021
		Carrying Value		Fair Value		Carrying Value		Fair Value			Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)									(In thousands)
Debt:	Debt:									Debt:
Revolving credit facility	Revolving credit facility	$	248,000	$	248,000	$	304,000	$	304,000	Revolving credit facility	$	250,000	$	250,000	$	304,000	$	304,000
5.375% senior notes due 2027(1)	5.375% senior notes due 2027(1)	$	473,005	$	490,137	$	472,727	$	498,992	5.375% senior notes due 2027(1)	$	424,383	$	411,802	$	472,727	$	498,992

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

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was determined using the ~~March 31,~~June 30, 2022 quoted market price, a Level 1 classification in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include ~~those~~mineral and royalty interests acquired in ~~a business combination, inventory,~~asset acquisitions and subsequent write-downs of our proved ~~and unproved~~ oil and natural gas ~~properties and other long-lived assets that are written down~~interests to fair value when they are impaired or held for sale.

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.business. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Partnership, cannot be predicted with certainty, the Partnership’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Partnership’s assessment. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

13. SUBSEQUENT EVENTS

Cash Distribution

On ~~April 27,~~July 26, 2022, the board of directors of the General Partner approved a cash distribution for the ~~first~~second quarter of 2022 of $~~0.67~~0.81 per common unit, payable on ~~May 19,~~August 23, 2022, to eligible unitholders of record at the close of business on ~~May 12,~~August 16, 2022.

Common Unit Repurchase Program

On ~~April 27,~~July 26, 2022, the board of directors of the General Partner increased the authorization of its common unit repurchase program from ~~$150.0~~$250.0 million to ~~$250.0~~$750.0 million.

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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, 2021. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

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

As of ~~March 31,~~June 30, 2022, 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 55% of our total units outstanding. Diamondback also owns and controls our General Partner.

Recent Developments

Commodity Prices

Prices for oil, natural gas and natural gas liquids 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. During 2021 and the first ~~quarter~~half of 2022, NYMEX WTI, has ranged from $47.62 to $123.70 per Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $2.45 to ~~$6.31~~$9.32 per ~~MMBtu. On April 13, 2022, the closing NYMEX WTI price for crude oil was $104.25 per Bbl and the closing NYMEX Henry Hub price of natural gas was $7.00 per MMBtu.~~MMBtu, with seven-year highs reached in 2022. The ~~Russian-Ukrainian military conflict and~~war in Ukraine, the COVID-19 pandemic, and recent measures to combat inflation have ~~contributed~~continued to contribute to economic and pricing volatility ~~in the first quarter of 2022 as industry and market participants evaluate global demand and production outlooks. On March 31, 2022,~~during 2022. Additionally, OPEC and its non-OPEC allies, known collectively as OPEC+, ~~agreed~~continues to ~~continue their program (commenced in August 2021)~~meet regularly to evaluate the state of ~~gradual monthly output increases, raising its output target by 432,000 Bbl per day for May 2022, which is expected to further boost~~global oil supply, ~~in response to rising demand. In its report issued on April 12,~~demand and inventory levels, and has planned production increases throughout 2022, ~~OPEC noted its expectation that world oil demand will rise by 3.7 million Bbls per day in 2022, down 480,000 Bbls per day from its previous forecast due to~~however such increases cannot be guaranteed. As such, pricing may remain volatile during the ~~impact~~second half of the Russian-Ukrainian military conflict, rising inflation and the resurgence of the Omicron coronavirus variant in China. Although this demand outlook is expected to underpin oil prices, already seen at a seven-year high in the first quarter of 2022, we cannot predict any future volatility in commodity prices or demand for crude oil.2022.

Although demand for oil and natural gas and commodity prices have ~~recently~~ increased in the current year, Diamondback and certain of our other operators have kept production on our acreage relatively flat during 2022, 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 will maintain its fourth quarter 2021 oil production levels 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.

Due to the improved commodity prices and industry conditions, we were not required to record an impairment on our proved oil and natural gas interests for the quarter ended ~~March 31,~~June 30, 2022, based on the results of the quarterly ceiling test. 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.

Acquisitions ~~and Divestitures~~ Update

~~In the first quarter~~We have had no significant acquisitions during of 2022, we had insignificant acquisitions and 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. This brought our2022. Our footprint of mineral and royalty interests ~~to a total of 26,708~~totaled 26,718 net royalty acres at ~~March 31,~~June 30, 2022.

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Cash Distributions on Common Units

On ~~April 27,~~July 26, 2022, the board of directors of our General Partner declared a cash distribution for the three months ended ~~March 31,~~June 30, 2022 of ~~$0.67~~$0.81 per common ~~unit, maintaining our distribution from the fourth quarter of 2021 of 70% of cash available for distribution.~~unit. The distribution is payable in the third quarter of 2022.

In July 2022, the board of directors of our General Partner approved a distribution policy, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our unit buyback program. This policy will be effective beginning with our distribution payable following the third quarter of 2022 and contemplates that we will return to our

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unitholders at least 75% of our cash available for distribution through a combination of base distribution, variable distribution and repurchases of limited partner units. The base distribution is intended initially to be $0.25 per unit quarterly ($1.00 per unit annually).

Repurchases of Notes

During the second quarter of 2022, the Partnership repurchased an aggregate $49.6 million principal amount of its outstanding 5.375% 2027 Senior Notes with a combination of cash on ~~May 19,~~hand and borrowing under the Operating Company’s revolving credit facility. For additional discussion of our debt transactions during the second quarter of 2022, see Note 6—Debt of the notes to ~~eligible common unitholders of record at~~ the close of business on May 12, 2022. 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.condensed consolidated financial statements included elsewhere in this report.

Production and Operational Update

Third party operated net wells turned to production on our acreage during the ~~first~~second quarter of 2022 are at their highest level since the second quarter of 2019, and third party operated gross wells turned to production during the quarter were the highest in the Partnership’s history. There are currently 4447 rigs operating on our mineral and royalty acreage, ~~eight~~seven of which are operated by Diamondback. Our production and free cash flow ~~outlook is~~outlooks are 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~~As a result of Diamondback’s consistent focus on developing our high concentration royalty acreage, primarily in the Northern Midland Basin, we increased our ~~production outlook~~full year 2022 guidance for ~~2022 and have a high level of visibility into Diamondback’s anticipated forward development plan that is expected to bolster~~ oil production ~~for Viper not only for~~by approximately 4% at the ~~next several quarters, but in~~midpoint from the ~~coming years.~~previous guidance.

The following table summarizes our gross well information as of the dates indicated:


		Diamondback Operated		Third Party Operated		Total			Diamondback Operated		Third Party Operated		Total
Horizontal wells turned to production (first quarter 2022)(1):
Horizontal wells turned to production (second quarter 2022)(1):								Horizontal wells turned to production (second quarter 2022)(1):
Gross wells	Gross wells	45		230		275		Gross wells	54		126		180
Net 100% royalty interest wells	Net 100% royalty interest wells	2.0		1.9		3.9		Net 100% royalty interest wells	4.8		0.9		5.7
Average percent net royalty interest	Average percent net royalty interest	4.4	%	0.8	%	1.4	%	Average percent net royalty interest	8.9	%	0.7	%	3.2	%

Horizontal producing well count (as of April 13, 2022):
Horizontal producing well count (as of July 13, 2022):								Horizontal producing well count (as of July 13, 2022):
Gross wells	Gross wells	1,384		4,357		5,741		Gross wells	1,451		4,521		5,972
Net 100% royalty interest wells	Net 100% royalty interest wells	104.2		60.4		164.6		Net 100% royalty interest wells	109.7		61.9		171.6
Average percent net royalty interest	Average percent net royalty interest	7.5	%	1.4	%	2.9	%	Average percent net royalty interest	7.6	%	1.4	%	2.9	%

Horizontal active development well count (as of April 13, 2022)(2):
Horizontal active development well count (as of July 13, 2022)(2):								Horizontal active development well count (as of July 13, 2022)(2):
Gross wells	Gross wells	91		382		473		Gross wells	75		475		550
Net 100% royalty interest wells	Net 100% royalty interest wells	6.8		3.7		10.5		Net 100% royalty interest wells	4.2		4.8		9.0
Average percent net royalty interest	Average percent net royalty interest	7.5	%	1.0	%	2.2	%	Average percent net royalty interest	5.6	%	1.0	%	1.6	%

Line of sight wells (as of April 13, 2022)(3):
Line of sight wells (as of July 13, 2022)(3):								Line of sight wells (as of July 13, 2022)(3):
Gross wells	Gross wells	167		511		678		Gross wells	145		413		558
Net 100% royalty interest wells	Net 100% royalty interest wells	9.4		3.6		13.0		Net 100% royalty interest wells	8.3		4.2		12.5
Average percent net royalty interest	Average percent net royalty interest	5.6	%	0.7	%	1.9	%	Average percent net royalty interest	5.7	%	1.0	%	2.2	%

(1) Average lateral length of ~~10,519.~~9,785.

(2) The total ~~473~~550 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 ~~678~~558 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.

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Comparison of the Three Months Ended June 30, 2022 and March 31, 2022

As noted in “—Recent Developments,” the markets for oil and ~~2021~~natural gas are highly volatile and are influenced by a number of factors which can lead to significant changes in our results of operations and management’s operational strategy on a quarterly basis. Accordingly, our results of operations discussion focuses on a comparison of the current quarter’s results of operations with those of the immediately preceding quarter. We believe our discussion provides investors with a more meaningful analysis of material operational and financial changes which occurred during the quarter based on current market and operational trends.

Results of Operations

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


		Three Months Ended March 31,					Three Months Ended
		2022		2021					June 30, 2022		March 31, 2022
		(In thousands)				(In thousands)

Operating income:	Operating income:							Operating income:
Oil income	Oil income	$	155,051	$	78,344			Oil income	$	191,195	$	155,051
Natural gas income	Natural gas income	15,190		9,044				Natural gas income	23,793		15,190
Natural gas liquids income	Natural gas liquids income	22,848		9,124				Natural gas liquids income	23,842		22,848
Royalty income	Royalty income	193,089		96,512				Royalty income	238,830		193,089
Lease bonus income	Lease bonus income	8,682		325				Lease bonus income	329		8,682

Other operating income	Other operating income	132		139				Other operating income	163		132
Total operating income	Total operating income	201,903		96,976				Total operating income	239,322		201,903
Costs and expenses:	Costs and expenses:							Costs and expenses:
Production and ad valorem taxes	Production and ad valorem taxes	13,870		6,649				Production and ad valorem taxes	16,039		13,870

Depletion	Depletion	27,411		24,886				Depletion	31,962		27,411

General and administrative expenses	General and administrative expenses	1,953		2,221				General and administrative expenses	1,880		1,953

Total costs and expenses	Total costs and expenses	43,234		33,756				Total costs and expenses	49,881		43,234
Income (loss) from operations	Income (loss) from operations	158,669		63,220				Income (loss) from operations	189,441		158,669
Other income (expense):	Other income (expense):							Other income (expense):
Interest expense, net	Interest expense, net	(9,645)		(7,860)				Interest expense, net	(9,782)		(9,645)

Gain (loss) on derivative instruments, net	Gain (loss) on derivative instruments, net	(18,359)		(31,504)				Gain (loss) on derivative instruments, net	(1,889)		(18,359)

Other income, net	Other income, net	6		38				Other income, net	32		6
Total other expense, net	Total other expense, net	(27,998)		(39,326)				Total other expense, net	(11,639)		(27,998)
Income (loss) before income taxes	Income (loss) before income taxes	130,671		23,894				Income (loss) before income taxes	177,802		130,671
Provision for (benefit from) income taxes	Provision for (benefit from) income taxes	2,630		35				Provision for (benefit from) income taxes	6,182		2,630
Net income (loss)	Net income (loss)	128,041		23,859				Net income (loss)	171,620		128,041
Net income (loss) attributable to non-controlling interest	Net income (loss) attributable to non-controlling interest	111,436		26,879				Net income (loss) attributable to non-controlling interest	137,598		111,436
Net income (loss) attributable to Viper Energy Partners LP	Net income (loss) attributable to Viper Energy Partners LP	$	16,605	$	(3,020)			Net income (loss) attributable to Viper Energy Partners LP	$	34,022	$	16,605

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


		Three Months Ended March 31,				Three Months Ended
		2022		2021				June 30, 2022		March 31, 2022
Production data:	Production data:						Production data:
Oil (MBbls)	Oil (MBbls)	1,633		1,395			Oil (MBbls)	1,798		1,633
Natural gas (MMcf)	Natural gas (MMcf)	3,729		3,262			Natural gas (MMcf)	3,898		3,729
Natural gas liquids (MBbls)	Natural gas liquids (MBbls)	586		407			Natural gas liquids (MBbls)	607		586
Combined volumes (MBOE)(1)	Combined volumes (MBOE)(1)	2,841		2,346			Combined volumes (MBOE)(1)	3,054		2,841

Average daily oil volumes (BO/d)	Average daily oil volumes (BO/d)	18,144		15,500			Average daily oil volumes (BO/d)	19,758		18,144
Average daily combined volumes (BOE/d)	Average daily combined volumes (BOE/d)	31,567		26,066			Average daily combined volumes (BOE/d)	33,560		31,567

Average sales prices:	Average sales prices:						Average sales prices:
Oil ($/Bbl)	Oil ($/Bbl)	$	94.95	$	56.16		Oil ($/Bbl)	$	106.34	$	94.95
Natural gas ($/Mcf)	Natural gas ($/Mcf)	$	4.07	$	2.77		Natural gas ($/Mcf)	$	6.10	$	4.07
Natural gas liquids ($/Bbl)	Natural gas liquids ($/Bbl)	$	38.99	$	22.42		Natural gas liquids ($/Bbl)	$	39.28	$	38.99
Combined ($/BOE)(2)	Combined ($/BOE)(2)	$	67.97	$	41.14		Combined ($/BOE)(2)	$	78.20	$	67.97

Oil, hedged ($/Bbl)(3)	Oil, hedged ($/Bbl)(3)	$	92.05	$	45.45		Oil, hedged ($/Bbl)(3)	$	105.59	$	92.05
Natural gas, hedged ($/Mcf)(3)	Natural gas, hedged ($/Mcf)(3)	$	3.71	$	2.77		Natural gas, hedged ($/Mcf)(3)	$	4.72	$	3.71
Natural gas liquids ($/Bbl)(3)	Natural gas liquids ($/Bbl)(3)	$	38.99	$	22.42		Natural gas liquids ($/Bbl)(3)	$	39.28	$	38.99
Combined price, hedged ($/BOE)(3)	Combined price, hedged ($/BOE)(3)	$	65.82	$	34.77		Combined price, hedged ($/BOE)(3)	$	75.99	$	65.82

Average costs ($/BOE):	Average costs ($/BOE):						Average costs ($/BOE):
Production and ad valorem taxes	Production and ad valorem taxes	$	4.88	$	2.83		Production and ad valorem taxes	$	5.25	$	4.88

General and administrative - cash component(4)	General and administrative - cash component(4)	0.59		0.81			General and administrative - cash component(4)	0.51		0.59
Total operating expense - cash	Total operating expense - cash	$	5.47	$	3.64		Total operating expense - cash	$	5.76	$	5.47

General and administrative - non-cash unit compensation expense	General and administrative - non-cash unit compensation expense	$	0.10	$	0.13		General and administrative - non-cash unit compensation expense	$	0.11	$	0.10
Interest expense, net	Interest expense, net	$	3.39	$	3.35		Interest expense, net	$	3.20	$	3.39
Depletion	Depletion	$	9.65	$	10.61		Depletion	$	10.47	$	9.65

(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.

Royalty Income

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

Royalty income increased ~~$96.6~~$45.7 million during the ~~first~~second quarter of 2022, compared to the ~~same period in 2021.~~first quarter of 2022. As discussed in “—Recent Developments,”, ~~the record high~~ higher oil prices and to a lesser extent, ~~the continuing recovery in~~ natural gas and natural gas liquids prices, contributed approximately ~~$77.9~~$28.5 million of the total increase.

The ~~21%~~remaining increase of $17.2 million stemmed from production growth of 8% primarily attributable to production from new wells and having one additional day of production in ~~production volumes during~~ the ~~first~~second quarter of 2022 compared to the ~~same period in 2021 contributed the remaining $18.7 million~~first quarter of ~~the total increase in royalty income. This production growth is primarily attributable to new well additions between periods.~~2022.

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Lease Bonus Income

Lease bonus income ~~increased~~decreased during the ~~first~~second quarter of 2022 ~~compared to the same period in 2021 due primarily to~~as a result of recording non-recurring income from leasing certain assets we acquired in the Swallowtail Acquisition to ~~Diamondback.~~Diamondback in the first quarter of 2022.

Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the three months ended June 30, 2022 and March 31, 2022 ~~and 2021~~:


		Three Months Ended March 31,													Three Months Ended
		2022						2021							June 30, 2022						March 31, 2022
		Amount (In thousands)		Per BOE		Percentage of Royalty Income		Amount (In thousands)		Per BOE		Percentage of Royalty Income			Amount (In thousands)		Per BOE		Percentage of Royalty Income		Amount (In thousands)		Per BOE		Percentage of Royalty Income
Production taxes	Production taxes	$	9,870	$	3.47	5.1	%	$	4,823	$	2.05	5.0	%	Production taxes	$	12,023	$	3.94	5.0	%	$	9,870	$	3.47	5.1	%
Ad valorem taxes	Ad valorem taxes	4,000		1.41		2.1		1,826		0.78		1.9		Ad valorem taxes	4,016		1.31		1.7		4,000		1.41		2.1
Total production and ad valorem taxes	Total production and ad valorem taxes	$	13,870	$	4.88	7.2	%	$	6,649	$	2.83	6.9	%	Total production and ad valorem taxes	$	16,039	$	5.25	6.7	%	$	13,870	$	4.88	7.2	%

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 ~~first~~second quarter of 2022 remained consistent with the ~~same period in 2021.~~first quarter of 2022. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes were consistent between periods and decreased as a percentage of royalty income for ~~first~~the second quarter of 2022 compared to the ~~same period in 2021 increased~~first quarter of 2022, primarily due to the increase in royalty income from higher ~~valuations assigned to our~~ oil and natural gas ~~interests period over period driven by higher commodity~~ prices.

Depletion

The ~~$2.5~~$4.6 million, or ~~10%~~17%, increase in depletion expense for the ~~first~~second quarter of 2022 compared to the ~~same period in 2021~~first quarter of 2022 was due primarily to higher production, ~~volumes, which was partially offset by a decrease~~coupled with an increase in the average depletion rate to ~~$9.65~~$10.47 from ~~$10.61,~~$9.65, respectively. The rate ~~decrease largely~~increase resulted from higher ~~SEC oil prices utilized in~~value leasehold being transferred into the ~~reserve calculations in~~amortization base during the ~~2022 period, lengthening the economic life~~second quarter of ~~the reserve base and resulting in higher projected remaining reserve volumes on our wells.~~2022.

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 March 31,					Three Months Ended
		2022		2021					June 30, 2022		March 31, 2022
		(In thousands)				(In thousands)
Gain (loss) on derivative instruments	Gain (loss) on derivative instruments	$	(18,359)	$	(31,504)			Gain (loss) on derivative instruments	$	(1,889)	$	(18,359)
Net cash receipts (payments) on derivatives(1)	Net cash receipts (payments) on derivatives(1)	$	(10,264)	$	(14,942)			Net cash receipts (payments) on derivatives(1)	$	(6,765)	$	(10,264)

(1)The three months ended March 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $4.2 million.

We recorded losses on our derivative instruments for the first and second quarters of 2022 primarily due to market prices being higher than the strike prices on our derivative contracts. However, due to the early termination of certain commodity contracts in the first quarter of 2022 and the continued settlement of contracts with more unfavorable pricing in the second quarter of 2022, market prices were closer to the strike prices on our open contracts at June 30, 2022 compared to March 31, 2022, which reduced our overall loss. 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.” See Note 10—Derivatives of the notes to the condensed consolidated financial statements included elsewhere in this report for additional discussion of our open contracts at June 30, 2022.

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Provision for (Benefit from) Income Taxes

The $3.6 million increase in income tax expense for the second quarter of 2022 compared to the first quarter of 2022. primarily resulted from higher pre-tax net income driven primarily by an increase in royalty income and a decrease in losses on our derivative contracts as discussed above. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements included elsewhere in this report for further details.

Comparison of the Six Months Ended June 30, 2022 and 2021

Results of Operations

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


	Six Months Ended June 30,
		2022		2021
		(In thousands)

Operating income:
Oil income		$	346,246	$	172,296
Natural gas income		38,983		18,577
Natural gas liquids income		46,690		19,097
Royalty income		431,919		209,970
Lease bonus income		9,011		809

Other operating income		295		347
Total operating income		441,225		211,126
Costs and expenses:
Production and ad valorem taxes		29,909		14,801

Depletion		59,373		48,864


General and administrative expenses		3,833		4,383

Total costs and expenses		93,115		68,048
Income (loss) from operations		348,110		143,078
Other income (expense):
Interest expense, net		(19,427)		(15,833)


Gain (loss) on derivative instruments, net		(20,248)		(61,050)

Other income, net		38		77
Total other expense, net		(39,637)		(76,806)
Income (loss) before income taxes		308,473		66,272
Provision for (benefit from) income taxes		8,812		35
Net income (loss)		299,661		66,237
Net income (loss) attributable to non-controlling interest		249,034		64,595
Net income (loss) attributable to Viper Energy Partners LP		$	50,627	$	1,642

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


	Six Months Ended June 30,
		2022		2021
Production data:
Oil (MBbls)		3,431		2,898
Natural gas (MMcf)		7,627		6,481
Natural gas liquids (MBbls)		1,193		856
Combined volumes (MBOE)(1)		5,895		4,834

Average daily oil volumes (BO/d)		18,956		16,011
Average daily combined volumes (BOE/d)		32,569		26,707


Average sales prices:
Oil ($/Bbl)		$	100.92	$	59.45
Natural gas ($/Mcf)		$	5.11	$	2.87
Natural gas liquids ($/Bbl)		$	39.14	$	22.31
Combined ($/BOE)(2)		$	73.27	$	43.44

Oil, hedged ($/Bbl)(3)		$	99.14	$	47.07
Natural gas, hedged ($/Mcf)(3)		$	4.22	$	2.87
Natural gas liquids ($/Bbl)(3)		$	39.14	$	22.31
Combined price, hedged ($/BOE)(3)		$	71.09	$	36.01

Average costs ($/BOE):
Production and ad valorem taxes		$	5.07	$	3.06

General and administrative - cash component(4)		0.55		0.77
Total operating expense - cash		$	5.62	$	3.83

General and administrative - non-cash unit compensation expense		$	0.11	$	0.14
Interest expense, net		$	3.30	$	3.28
Depletion		$	10.07	$	10.11

(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.

Royalty Income

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

Royalty income increased $221.9 million during the six months ended June 30, 2022 compared to the same period in 2021. As discussed in “—Recent Developments,” the record high oil prices and to a lesser extent, the continuing recovery in natural gas and natural gas liquids prices, contributed approximately $179.4 million of the total increase.

The 22% increase in production volumes during the six months ended June 30, 2022 compared to the same period in 2021 contributed to the remaining $42.5 million of the total increase in royalty income. This production growth is primarily attributable to new well additions between periods, largely resulting from the Swallowtail Acquisition.

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Lease Bonus Income

Lease bonus income increased during the six months ended June 30, 2022 compared to the same period in 2021 due primarily to leasing certain assets we acquired in the Swallowtail Acquisition to Diamondback in the first quarter of 2022.

Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
	2022						2021
	Amount (In thousands)		Per BOE		Percentage of Royalty Income		Amount (In thousands)		Per BOE		Percentage of Royalty Income
Production taxes	$	21,894	$	3.71	5.1	%	$	10,514	$	2.17	5.0	%
Ad valorem taxes	8,015		1.36		1.9		4,287		0.89		2.0
Total production and ad valorem taxes	$	29,909	$	5.07	7.0	%	$	14,801	$	3.06	7.0	%

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 six months ended June 30, 2022 remained consistent with the same period in 2021. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. The increase in ad valorem taxes is primarily due to accruing taxes for the properties acquired in the Swallowtail Acquisition, as well as higher valuations assigned to our other oil and natural gas interests period over period driven by higher commodity prices. Ad valorem taxes remained consistent as a percentage of royalty income for the six months ended June 30, 2022 compared to the same period in 2021.

Depletion

The $10.5 million, or 22%, increase in depletion expense for the six months ended June 30, 2022 compared to the same period in 2021 was due primarily to production growth between the periods. The average depletion rate of $10.07 for the six months ended June 30, 2022 remained consistent with the rate of $10.11 for the same period in 2021.

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:


	Six Months Ended June 30,
	2022		2021
	(In thousands)
Gain (loss) on derivative instruments	$	(20,248)	$	(61,050)
Net cash receipts (payments) on derivatives(1)	$	(17,029)	$	(35,882)

(1)The six months ended June 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $4.2 million.

We recorded losses on our derivative instruments for the ~~three~~six months ended ~~March 31,~~June 30, 2022 and 2021 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.”

~~Table of Contents~~

~~Comparison of the Three Months Ended March 31, 2022 and December 31, 2021~~

~~As noted in “~~—~~Recent Developments~~”, the markets for oil and natural gas are highly volatile and are influenced by a number of factors which can lead to significant changes in our results of operations and management’s operational strategy on a quarterly basis. As a result, beginning with the first quarter of 2022, we have elected to change our results of operations discussion to focus on a comparison of the current quarter’s results of operations with those of the immediately preceding quarter. We believe the change in our discussion will provide investors with a more meaningful analysis of material operational and financial changes which occurred during the quarter based on current market and operational trends.

~~Results of Operations~~

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

Three Months Ended
March 31, 2022 December 31, 2021
(In thousands)
Operating income:
Oil income $ 155,051 $ 125,063
Natural gas income 15,190 18,546
Natural gas liquids income 22,848 20,306
Royalty income 193,089 163,915
Lease bonus income 8,682 1,731
Other operating income 132 141
Total operating income 201,903 165,787
Costs and expenses:
Production and ad valorem taxes 13,870 9,132
Depletion 27,411 28,757
General and administrative expenses 1,953 1,682
Total costs and expenses 43,234 39,571
Income (loss) from operations 158,669 126,216
Other income (expense):
Interest expense, net (9,645) (9,883)
Gain (loss) on derivative instruments, net (18,359) 1,240
Other income, net 6 2
Total other expense, net (27,998) (8,641)
Income (loss) before income taxes 130,671 117,575
Provision for (benefit from) income taxes 2,630 580
Net income (loss) 128,041 116,995
Net income (loss) attributable to non-controlling interest 111,436 77,530
Net income (loss) attributable to Viper Energy Partners LP $ 16,605 $ 39,465

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

Three Months Ended
March 31, 2022 December 31, 2021
Production data:
Oil (MBbls) 1,633 1,690
Natural gas (MMcf) 3,729 3,844
Natural gas liquids (MBbls) 586 554
Combined volumes (MBOE)(1)
2,841 2,885
Average daily oil volumes (BO/d) 18,144 18,370
Average daily combined volumes (BOE/d) 31,567 31,359
Average sales prices:
Oil ($/Bbl) 94.95 74.00
Natural gas ($/Mcf) 4.07 4.82
Natural gas liquids ($/Bbl) 38.99 36.65
Combined ($/BOE)(2)
67.97 56.82
Oil, hedged ($/Bbl)(3)
92.05 55.42
Natural gas, hedged ($/Mcf)(3)
3.71 4.82
Natural gas liquids ($/Bbl)(3)
38.99 36.65
Combined price, hedged ($/BOE)(3)
65.82 45.94
Average costs ($/BOE):
Production and ad valorem taxes $ 4.88 $ 3.17
General and administrative - cash component(4)
0.59 0.48
Total operating expense - cash $ 5.47 $ 3.65
General and administrative - non-cash unit compensation expense $ 0.10 $ 0.10
Interest expense, net $ 3.39 $ 3.43
Depletion $ 9.65 $ 9.97

~~(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.~~

~~Royalty~~(Benefit from) 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 $29.2 million during the first quarter of 2022, compared to the fourth quarter of 2021. As discussed in “—Recent Developments~~”, the record high oil prices and to a lesser extent, the continuing recovery in natural gas and natural gas liquids prices, partially offset by a decrease in average natural gas prices, contributed approximately $32.8 million of the total increase.

The 2% decrease in production volumes during the first quarter of 2022 compared to the fourth quarter of 2021 offset approximately $3.6 million of the total increase in royalty income. The decrease in production is primarily due to having two fewer days of production in the first quarter of 2022 compared to the fourth quarter of 2021.

~~Table of Contents~~

~~Lease Bonus Income~~

~~Lease bonus income increased during the first quarter of 2022 compared to the fourth quarter of 2021 due primarily to leasing certain assets we acquired in the Swallowtail Acquisition to Diamondback.~~

~~Production and Ad Valorem~~ Taxes

~~The following table presents production and ad valorem taxes~~ ~~for thethree months ended March 31, 2022~~ ~~and December 31, 2021~~:

Three Months Ended
March 31, 2022 December 31, 2021
Amount
(In thousands) Per BOE Percentage of Royalty Income Amount
(In thousands) Per BOE Percentage of Royalty Income
Production taxes $ 9,870 $ 3.47 5.1 % $ 8,702 $ 3.02 5.3 %
Ad valorem taxes 4,000 1.41 2.1 430 0.15 0.3
Total production and ad valorem taxes $ 13,870 $ 4.88 7.2 % $ 9,132 $ 3.17 5.6 %

~~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 months ended March 31, 2022~~ remained consistent with the three months ended December 31, 2021. 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 the first quarter of 2022 compared to the fourth quarter of 2021. The increase is primarily due to the fourth quarter of 2021 including a downward revision to ad valorem taxes accrued for the full year of 2021 based on actual assessments received from ourIncome tax jurisdictions. Additionally, ad valorem tax accrued in the first quarter of 2022 increased due to higher expected valuations of our oil and natural gas interests in 2022 driven by higher commodity prices.

~~Depletion~~

~~The $1.3 million, or 5%, decrease in depletion~~ expense for the ~~first quarter~~six months ended June 30, 2022 of ~~2022 compared to~~$8.8 million resulted from the ~~fourth quarter of 2021~~increase in pre-tax income, which was ~~due primarily to~~driven largely by increases in royalty income and lease bonus income as well as a decrease in ~~production, coupled with a decline in the depletion rate to $9.65~~losses from ~~$9.97, respectively. The rate decrease largely resulted from higher SEC oil prices utilized in the reserve calculations in the 2022 period, lengthening the economic life~~our derivative contracts as discussed above. See Note 9—I ncome Taxes of the ~~reserve base and resulting in higher projected remaining reserve volumes on our wells.~~

~~Derivative Instruments~~

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

Three Months Ended
March 31, 2022 December 31, 2021
(In thousands)
Gain (loss) on derivative instruments $ (18,359) $ (1,240)
Net cash receipts (payments) on derivatives(1)
$ (10,264) $ (31,397)

~~(1)The first quarter of 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $4.2 million.~~

We recorded losses on our derivative instruments for the three months ended March 31, 2022 and December 31, 2021 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 financial statements ~~of operations under the line item captioned “Gain (loss) on derivative instruments, net.”~~

~~Table of Contents~~included elsewhere in this report for further details.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations and liquidity requirements. Our future ability to grow proved reserves will be highly dependent on the capital resources available to us. 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 the Operating Company’s credit agreement. Our primary uses of cash have been distributions to our unitholders, repayment of debt, capital expenditures for the acquisition of our mineral interests and royalty interests in oil and natural gas properties and repurchases of our common units and senior notes. At ~~March 31,~~June 30, 2022, we had approximately ~~$285.1~~$254.3 million of liquidity consisting of ~~$33.1~~$4.3 million in cash and cash equivalents and ~~$252.0~~$250.0 million available under the Operating Company’s credit agreement.

Our working capital requirements are supported by our cash and cash equivalents and the Operating Company’s credit agreement. We may draw on the Operating Company’s credit agreement to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our acquisitions of mineral and royalty interests, distributions, debt service obligations and repayment of debt maturities, common unit and senior note repurchases and any amounts that may ultimately be paid in connection with contingencies.

In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts as discussed further in Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.

Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the ~~Russian-Ukrainian military conflict,~~war in Ukraine, the depressed commodity markets and, or adverse macroeconomic conditions, including persistent inflation, rising interests rates and increasing concerns over a potential recession, may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although we expect that our sources of funding will be adequate to fund our short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.

Cash Flows

The following table presents our cash flows for the periods indicated:


		Three Months Ended March 31,					Six Months Ended June 30,
		2022		2021			2022		2021
		(In thousands)					(In thousands)
Cash Flow Data:	Cash Flow Data:					Cash Flow Data:
Net cash provided by (used in) operating activities	Net cash provided by (used in) operating activities	$	135,838	$	54,659	Net cash provided by (used in) operating activities	$	299,020	$	129,680
Net cash provided by (used in) investing activities	Net cash provided by (used in) investing activities	31,957		(74)		Net cash provided by (used in) investing activities	31,198		(819)
Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities	(174,177)		(61,979)		Net cash provided by (used in) financing activities	(365,354)		(105,560)
Net increase (decrease) in cash and cash equivalents	Net increase (decrease) in cash and cash equivalents	$	(6,382)	$	(7,394)	Net increase (decrease) in cash and cash equivalents	$	(35,136)	$	23,301

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 volumes of oil and natural gas sold by our producers as discussed in “—Result s 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. Th~~ese factors are beyond our control and are difficult to predict.~~ The increase in net cash provided by operating activities during the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to the same

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period in 2021 was primarily driven by (i) higher royalty income, (ii) an increase in lease bonus income and (iii) a decrease in cash paid for derivative settlements. These increases in cash flow were partially offset by (i) changes in our working capital accounts, most notably through an increase in our accounts receivable in 2022 compared to 2021 due primarily to higher market prices for our oil sales and the timing of our receipt of

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royalty income payments from our operators ~~and~~ (ii) an increase in production and ad valorem expenses due to the corresponding increase in royalty ~~income.~~income and (iii) an increase in cash paid for taxes, as our tax provision reflects an increase in current cash income taxes.

Investing Activities

Net cash provided by investing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2022, was primarily related to proceeds from the divestitures of oil and natural gas interests. There were no significant acquisitions or divestitures of oil and natural gas interests during the ~~three~~six months ended ~~March 31,~~June 30, 2021.

Financing Activities

Consistent with our previously announced strategy to return cash flow to unitholders, net cash used in financing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2022 was primarily related to distributions of ~~$78.9~~$194.1 million to our unitholders and ~~$39.3~~$68.2 million of common unit repurchases ~~during~~which included approximately $37.3 million for the ~~first quarter~~repurchase of ~~2022~~1.5 million common units from a significant unitholder in a privately negotiated transaction. Additionally, we paid $49.0 million for the repurchase of principal outstanding on the Notes as discussed ~~below. Additionally, we~~in “—2022 Debt Transactions” below and made net repayments of ~~$56.0~~$54.0 million on the Operating Company’s revolving credit facility.

Net cash used in financing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2021, was primarily related to the net repayment of ~~$27.0~~$22.0 million of borrowings under the Operating Company’s revolving credit facility, distributions of ~~$21.9~~$60.8 million to our unitholders and ~~$13.0~~$19.8 million of repurchases of our common units during the ~~first~~second quarter of ~~2021 as discussed below.~~2021.

Capital Resources

The Operating Company’s Revolving Credit Facility

The Operating Company’s credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $580.0 million as of ~~March 31,~~June 30, 2022, based on the Operating Company’s oil and natural gas reserves and other factors. At ~~March 31,~~June 30, 2022, the Operating Company had elected a commitment amount of $500.0 million on its credit agreement with ~~$248.0~~$250.0 million of outstanding borrowings. ~~The borrowing base of $580.0 million is expected to be reaffirmed by the lenders during the regularly scheduled (semi-annual) spring 2022 redetermination in May 2022.~~ During the three and six months ended ~~March 31,~~June 30, 2022, the weighted average interest rate on borrowings under the Operating Company’s revolving credit facility was ~~2.58%.~~3.20% and 2.88%, respectively.

As2022 Debt Transactions

During the second quarter of ~~March 31,~~ 2022, the Operating Company ~~was~~used a combination of cash on hand and borrowings under the Operating Company’s credit agreement to repurchase a portion of the 5.375% 2027 Senior Notes in the aggregate principal amount of $49.6 million.

The Operating Company is currently in compliance, and expects to be in compliance, with all financial maintenance covenants under its credit agreement.

See Note 6—Debt of the notes to the condensed consolidated financial statements included elsewhere in this report for additional discussion of our outstanding debt at ~~March 31,~~June 30, 2022.

Capital Requirements

Repurchases of Securities

On ~~November 15, 2021,~~April 27, 2022, the board of directors of our General Partner approved an increase of the authorization of its common unit repurchase program to $~~150.0~~250.0 million of our outstanding common units and extended the authorization indefinitely. ~~During~~On July 26, 2022, the ~~three months ended March 31, 2022, we repurchased approximately $39.3 million~~board of directors of our General Partner increased the authorization of our common ~~units under the~~unit repurchase program ~~which includes approximately $37.3~~from $250.0 million ~~for the repurchase of 1.5 million common units from an affiliate in a privately negotiated transaction.~~to $750.0 million. As of ~~March 31,~~June 30, 2022, ~~$40.7~~$111.8 million remains available for use to repurchase units under the repurchase program. See Note 7—Unitholders' Equity and Distributions of the notes to our

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condensed consolidated financial statements included elsewhere in this report for further discussion of the unit repurchase program.

We may also from time to time opportunistically repurchase some of the outstanding Notes in open market purchases or in privately negotiated transactions.

Cash Distributions

The distribution for the ~~first~~second quarter of 2022 ~~of $0.67~~was $0.81 per common unit is payable on ~~May 19,~~August 23, 2022 to common unitholders of record at the close of business on ~~May 12,~~August 16, 2022. See “—Recent Developments—Cash Distributions on Common Units” and Note 7—Unitholders' Equity and Distributions of the notes to the condensed consolidated financial statements included elsewhere in this report for further discussion of our distributions.

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Critical Accounting Estimates

There have been no changes to our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2021.

Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies to the notes of our condensed consolidated financial statements included elsewhere in this report for a listing of our significant accounting policies.

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, such as the ~~Russian-Ukrainian military conflict,~~war in Ukraine, the COVID-19 pandemic and actions taken by OPEC members and other exporting nations. 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 ~~March 31,~~June 30, 2022, we had a net liability derivative position related to our commodity price derivatives of ~~$11.5~~$6.6 million. Utilizing actual derivative contractual volumes under our contracts as of ~~March 31,~~June 30, 2022, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position by ~~$4.8~~$4.7 million to ~~$16.3~~$11.3 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position by ~~$4.2~~$3.7 million to ~~$7.3~~$2.9 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.

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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

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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 is the least of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. As of ~~March 31,~~June 30, 2022, we had ~~$248.0~~$250.0 million in outstanding borrowings. During the three and six months ended ~~March 31,~~June 30, 2022, the weighted average interest rate on the Operating Company’s revolving credit facility was ~~2.58%.~~3.20% and 2.88%, respectively.

ITEM 4. CONTROLS AND PROCEDURES

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

As of ~~March 31,~~June 30, 2022, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner have concluded that as of ~~March 31,~~June 30, 2022, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended ~~March 31,~~June 30, 2022 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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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~~As of the date of this filing, we continue to be subject to the ~~information set forth in this report, you should carefully consider the~~ risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 24, 2022, Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022, filed with the SEC on May 5, 2022, and in subsequent filings we make with the SEC. Except as provided below, there have been no material changes in our risk factors from those described in such reports.

Transition risks relating to climate change may have a material and adverse effect on us.

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been increasingly focused on climate change matters in recent years. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in:

•the enactment of climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures;

•technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology);

•increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and

•development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.

Any of these developments, which relate to the transition from hydrocarbon energy sources to alternative energy sources and therefore to a lower-carbon economy, may reduce the demand for products manufactured with (or powered by) hydrocarbons and the demand for, and in turn the prices of, the oil and natural gas that our operators produce and sell, which would likely have a material and adverse impact on us. Please see the risk factor in our Annual Report on Form 10-K for the year ended December 31, ~~2021.~~2021 titled “Our business has been and could continue to be adversely affected by the ongoing COVID-19 pandemic and volatility in the oil and natural gas markets” and “We depend on a small number of operators for a substantial portion of the development and production on the properties underlying our mineral interests. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of an operator to adequately and efficiently develop and operate our acreage could have an adverse effect on our expected growth and our results of operations” for more information regarding the potential impact on us of reduced demand for oil and natural gas.

~~We cannot predict~~If any of these developments reduce the ~~impact~~desirability of participating in the oilfield services, midstream or downstream portions of the ~~ongoing military conflict between Russia~~oil and ~~Ukraine~~gas industry, then these developments may also reduce the availability to our operators of necessary third-party services and facilities that they rely on, which could increase their operational costs and adversely affect their ability to explore for, produce, transport and process oil and natural gas and successfully carry out their business and financial strategy, which in turn could have an adverse effect on our business, financial condition and cash flow. These developments could also reduce the ~~related humanitarian crisis on~~number of customers willing to purchase the ~~global economy, energy markets, geopolitical stability~~oil and natural gas that our ~~business.~~operators produce.

~~Our~~

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In addition to potentially reducing demand for oil and natural gas and potentially reducing the availability of oilfield services and midstream and downstream customers to our operators, any of these developments may also create reputational risks associated with the oil and gas sector, which may adversely affect the availability and cost of capital to us. For example, a number of prominent investors have publicly announced their intention to no longer invest in the oil and gas sector in response to concerns related to climate change, and other financial institutions and investors may decide to do likewise in the future. If financial institutions and other investors refuse to invest in or provide capital to the oil and gas sector in the future because of these reputational risks, that could result in capital being unavailable to us, or only at significantly increased cost. Please see the risk factor in our Annual Report on Form 10-K for the year ended December 31, 2021 titled “Increased costs of capital could adversely affect our business” for more information regarding our need for capital and the potential impact on us of an increased cost of, or unavailability of, capital.

In addition, the enactment of climate change-related regulations, policies and initiatives may also result in increases in our operators’ compliance and other operating costs and have other adverse effects, such as a greater potential for governmental investigations or litigation, which may impair their ability to explore and develop our mineral and royalty acreage, all of which could adversely impact our business, financial condition and cash flows. For further discussion regarding the risks to us and our operators of climate change-related regulations, policies and initiatives, please see the discussion in our Annual Report on Form 10-K for the year ended December 31, 2021 in the section entitled “Business—Regulation—Climate Change.” Please also see the risk factors in our Annual Report on Form 10-K for the year ended December 31, 2021 titled “Changes in environmental laws could increase our operators’ costs and adversely impact our business, financial condition and cash flows” for more information regarding the potential impact on us and our operators of increased environmental regulations.

Continuing political and social concerns relating to climate change may result in significant litigation and related expenses.

Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect us. For example, shareholder activism has recently been increasing in our industry. Because of our structure as a limited partnership, we do not hold annual meetings or file proxy statements and our unitholders have limited voting rights. They may, however, attempt to effect changes to our business or governance to deal with climate change-related issues by public campaigns, investor communications, regulatory lobbying efforts or otherwise, which may result in significant management distraction and potentially significant expense.

Additionally, cities, counties, and other governmental entities in several states in the U.S. have filed lawsuits against energy companies seeking damages allegedly associated with climate change. Similar lawsuits may be filed in other jurisdictions. If any such lawsuits were to be filed against us, we could incur substantial legal defense costs and, if any such litigation were adversely determined, we could incur substantial damages.

Any of these climate change-related litigation risks could result in unexpected costs, negative sentiments about our company, disruptions to our business, and increases to our operating expenses, which in turn could have an adverse effect on our business, financial condition and cash flow.

The producing properties in which we have mineral and royalty interests are concentrated in the Permian Basin of West Texas, making us vulnerable to risks (including weather-related risks) associated with a single geographic area. In addition, a large amount of our proved reserves is ~~located primarily~~attributable to a small number of producing horizons within this area.

The producing properties in which we have mineral and royalty interests are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints faced by our operators or their customers, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids on our mineral and royalty acreage, and extreme weather conditions, such as the severe winter storms in the Permian Basin in ~~West Texas. However,~~February 2021, and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities on our mineral and royalty acreage.

Extreme regional weather events may occur that can affect our operators’ suppliers or customers, which could adversely affect us. For example, a significant hurricane or similar weather event could damage refining and other oil and natural gas-related facilities on the ~~broader consequences~~Gulf Coast of Texas and Louisiana, which (if significant enough) could limit the availability of gathering and transportation facilities across Texas and could then cause production in the Permian Basin (including potentially production on our mineral and royalty acreage) to be curtailed or shut in or (in the case of natural gas) flared. Further, any increase in flaring of natural gas production on our mineral and royalty acreage due to weather-related events or otherwise could expose us to reputational risks and adversely impact our or our operators’ contractual and other business

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relationships. Any of the ~~Russian-Ukrainian military conflict, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may~~above-referenced events could have a material adverse ~~effects~~effect on ~~global macroeconomic conditions, increase volatility~~us. Likewise, a weather event like the severe winter storms in the ~~price~~Permian Basin in February 2021 could reduce the availability of electrical power, road accessibility, and transportation facilities, which could have an adverse impact on production volumes on our mineral and royalty acreage (and therefore on our financial condition and results of operations).

In addition, the effect of fluctuations on supply and demand ofmay become more pronounced within specific geographic oil and natural gas ~~increase exposure~~producing areas such as the Permian Basin, which may cause these conditions to ~~cyberattacks, cause disruptions~~occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our mineral and royalty acreage, we could experience any of these conditions at the same time, resulting in ~~global supply chains, increase foreign currency fluctuations, cause constraints~~a relatively greater impact on us than they might have on other companies that have a more diversified portfolio of assets. Such delays or ~~disruption in the capital markets and limit sources of liquidity. We cannot predict the extent of the conflict’s~~interruptions could have a material adverse effect on our business, financial condition and ~~results of operations as well as on the global economy and energy markets.~~cash flow.

In addition to the geographic concentration of our mineral and royalty acreage, as of December 31, 2021, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause our operators to permanently or temporarily shut-in all of wells on our mineral and royalty acreage.

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

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common unit repurchase activity for the three months ended ~~March 31,~~June 30, 2022 was as follows:

Period
Total Number of Units Purchased(1)
Average Price Paid Per Unit(2)
Total Number of Units Purchased as Part of Publicly Announced Plan
Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(3)
(In thousands, except unit amounts)
January 1, 2022 - January 31, 2022 1,580,200 $ 24.85 1,580,200 $ 40,715
February 1, 2022 - February 28, 2022 — $ — — $ 40,715
March 1, 2022 - March 31, 2022 — $ — — $ 40,715
Total 1,580,200 $ 24.85 1,580,200


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)
April 1, 2022 - April 30, 2022	—	$	—	—	$	140,715
May 1, 2022 - May 31, 2022	600,000	$	28.98	600,000	$	123,330
June 1, 2022 - June 30, 2022	420,000	$	27.53	420,000	$	111,766
Total	1,020,000	$	28.38	1,020,000

(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)The board of directors of our General Partner initially approved a $100.0 million common unit repurchase program in November of 2020 and, effective November 15, 2021, increased our authorization under this program to acquire up to $150.0 million of our outstanding common units and extended the term of the repurchase program indefinitely. In April 2022, the repurchase program authorization was further increased to $250.0 million. On ~~April 27,~~July 26, 2022 the board of directors of our General Partner increased the authorization of our common unit repurchase program ~~from $150.0 million~~ to ~~$250.0~~$750.0 million. This repurchase program remains 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						Purchase and Sale Agreement dated August 6, 2021 by and among Swallowtail Royalties LLC, Swallowtail Royalties II LLC (collectively, as seller), Viper Energy Partners LLC (as buyer) and Viper Energy Partners LP (as parent, and collectively with Viper Energy Partners LLC, as buyer parties) (incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on August 12, 2021).
3.1						Certificate of Limited Partnership of Viper Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File 333-195769) filed on May 7, 2014).
3.2						Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 9, 2018 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.3						First Amendment to Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 10, 2018. (incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.4						Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of May 9, 2018. (incorporated by reference to Exhibit 3.3 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.5						First Amendment to Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of March 30, 2020 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on March 31, 2020).

3.6						Second Amendment to the Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of December 27, 2021 (incorporated by reference to 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on December 28, 2 ~~021)~~2021).
4.1						Amended and Restated Registration Rights Agreement, dated as of May 9, 2018, by and between Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).







4.2						Registration Rights Agreement, dated as of October 1, 2021, by and among Viper Energy Partners LP, Swallowtail Royalties LLC and Swallowtail Royalties II LLC (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on October 7, 2021).
31.1*						Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*						Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**						Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101						The following financial information from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended ~~March 31,~~June 30, 2022, 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:	~~May 5,~~August 3, 2022	By:	/s/ Travis D. Stice
			Travis D. Stice
			Chief Executive Officer

Date:	~~May 5,~~August 3, 2022	By:	/s/ Teresa L. Dick
			Teresa L. Dick
			Chief Financial Officer

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