UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the Quarterly Period Ended September 30, ~~2022~~2023


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-36505

Viper Energy Partners LP

(Exact Name of Registrant As Specified in Its Charter)

46-5001985

(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification Number)

500 West Texas Ave.

Suite 100

Midland, TX

79701

(Address of principal executive offices)

(Zip code)

(432) 221-7400

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units

VNOM

The Nasdaq Stock Market LLC

(NASDAQ Global Select Market)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One):

Large Accelerated Filer

☒

Accelerated Filer

☐

Non-Accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

As of November ~~4, 2022,~~3, 2023, the registrant had outstanding ~~74,185,141~~87,144,273 common units representing limited partner interests and 90,709,946 Class B units representing limited partner interests.

VIPER ENERGY PARTNERS LP

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, ~~2022~~2023

TABLE OF CONTENTS


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

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			1819

Item 3. Quantitative and Qualitative Disclosures about Market Risk			2830

Item 4. Controls and Procedures			2931

PART II. OTHER INFORMATION
Item 1. Legal Proceedings			3033

Item 1A. Risk Factors			3033

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			3033

Item 5. Other Information			33

Item 6. Exhibits			3134

Signatures			3236

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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”):



Argus WTI Midland			Grade of oil that serves as a benchmark price for oil at Midland, Texas.
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.

















Henry Hub			Natural gas gathering point that serves as a benchmark price for natural gas futures on the NYMEX.
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.
MMcf			Million cubic feet of natural gas.




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.
Waha Hub			Natural gas gathering point that serves as a benchmark price for natural gas at western Texas and New Mexico.






WTI			West Texas ~~Intermediate.~~Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil that serves as a benchmark for oil on the NYMEX.
WTI Cushing			Grade of oil that serves as a benchmark price for oil at Cushing, Oklahoma.

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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, non-cash (gain) loss on derivative instruments 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.
Nasdaq			The Nasdaq Global Select Market.
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.

SOFR			The secured overnight financing rate.
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; our intent to convert into a corporate structure and expectations regarding the timing of such conversion, potential inclusion into certain indices and benchmarks, trading liquidity, tax treatment for our public unitholders post-conversion and related statements; anticipated benefits other of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including Diamondback’s plans for developing our acreage and our cash distribution policy and repurchases of our common units and/or senior notes) are forward-looking statements. When used in this report, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to us are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II. Item 1A. Risk Factors, and our Annual Report on Form 10-K for the year ended December 31, ~~2021, our~~ ~~Quarterly Report on Form 10-Q~~ ~~for the quarterly period ended March 31, 2022 and our~~ ~~Quarterly Report on Form 10-Q~~ ~~for the quarterly period ended June 30,~~ 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~~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, instability in the financial sector and concerns over a potential economic downturn or 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;

•physical and 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 our operators or third parties with whom we transact business;

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

•severe weather conditions;

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

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

•changes in our credit rating; and

•other risks and factors disclosed in this report.

In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, new risks emerge from time to time. We cannot predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this report. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by applicable law.

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Viper Energy Partners LP

Condensed Consolidated Balance Sheets

(Unaudited)

September 30, December 31,
2022 2021
(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents $ 11,616 $ 39,448
Royalty income receivable (net of allowance for credit losses) 94,215 68,568
Royalty income receivable—related party 10,267 2,144
Derivative instruments 4,686 —
Other current assets 3,506 989
Total current assets 124,290 111,149
Property:
Oil and natural gas interests, full cost method of accounting ($1,460,744 and $1,640,172 excluded from depletion at September 30, 2022 and December 31, 2021, respectively) 3,493,979 3,513,590
Land 5,688 5,688
Accumulated depletion and impairment (688,996) (599,163)
Property, net 2,810,671 2,920,115
Derivative instruments 839 —
Deferred income taxes (net of allowances) 49,656 —
Other assets 301 2,757
Total assets $ 2,985,757 $ 3,034,021
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable $ 17 $ 69
Accrued liabilities 24,173 20,509
Derivative instruments 891 3,417
Income taxes payable — 471
Total current liabilities 25,081 24,466
Long-term debt, net 669,638 776,727
Derivative instruments 125 —
Total liabilities 694,844 801,193
Commitments and contingencies (Note 12)
Unitholders’ equity:
General Partner 669 729
Common units (74,156,051 units issued and outstanding as of September 30, 2022 and 78,546,403 units issued and outstanding as of December 31, 2021) 722,397 813,161
Class B units (90,709,946 units issued and outstanding as of September 30, 2022 and December 31, 2021) 857 931
Total Viper Energy Partners LP unitholders’ equity 723,923 814,821
Non-controlling interest 1,566,990 1,418,007
Total equity 2,290,913 2,232,828
Total liabilities and unitholders’ equity $ 2,985,757 $ 3,034,021


	September 30,		December 31,
	2023		2022
	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	146,814	$	18,179

Royalty income receivable (net of allowance for credit losses)	103,804		81,657
Royalty income receivable—related party	7,431		6,260
Derivative instruments	—		9,328
Other current assets	4,081		3,196
Total current assets	262,130		118,620
Property:
Oil and natural gas interests, full cost method of accounting ($1,151,711 and $1,297,221 excluded from depletion at September 30, 2023 and December 31, 2022, respectively)	3,592,768		3,464,819
Land	5,688		5,688
Accumulated depletion and impairment	(821,565)		(720,234)
Property, net	2,776,891		2,750,273
Funds held in escrow	50,000		—
Derivative instruments	—		442
Deferred income taxes (net of allowances)	48,768		49,656
Other assets	5,577		1,382
Total assets	$	3,143,366	$	2,920,373
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	197	$	1,129
Accounts payable—related party	—		306
Accrued liabilities	24,688		19,600
Derivative instruments	9,284		—
Income taxes payable	13,322		911
Total current liabilities	47,491		21,946
Long-term debt, net	675,681		576,895

Derivative instruments	1,619		7
Total liabilities	724,791		598,848
Commitments and contingencies (Note 12)

Unitholders’ equity:
General Partner	589		649
Common units (70,861,557 units issued and outstanding as of September 30, 2023 and 73,229,645 units issued and outstanding as of December 31, 2022)	712,728		689,178
Class B units (90,709,946 units issued and outstanding as of September 30, 2023 and December 31, 2022)	757		832
Total Viper Energy Partners LP unitholders’ equity	714,074		690,659
Non-controlling interest	1,704,501		1,630,866
Total equity	2,418,575		2,321,525
Total liabilities and unitholders’ equity	$	3,143,366	$	2,920,373

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 September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(In thousands, except per unit amounts)
Operating income:
Royalty income $ 219,909 $ 127,649 $ 651,828 $ 337,619
Lease bonus income 1,497 223 10,508 1,032
Other operating income 211 132 506 479
Total operating income 221,617 128,004 662,842 339,130
Costs and expenses:
Production and ad valorem taxes 15,638 8,625 45,547 23,426
Depletion 30,460 25,366 89,833 74,230
General and administrative expenses 2,139 1,735 5,972 6,118
Total costs and expenses 48,237 35,726 141,352 103,774
Income (loss) from operations 173,380 92,278 521,490 235,356
Other income (expense):
Interest expense, net (10,731) (8,328) (30,158) (24,161)
Gain (loss) on derivative instruments, net 882 (9,599) (19,366) (70,649)
Other income, net 162 — 200 77
Total other expense, net (9,687) (17,927) (49,324) (94,733)
Income (loss) before income taxes 163,693 74,351 472,166 140,623
Provision for (benefit from) income taxes (46,409) 906 (37,597) 941
Net income (loss) 210,102 73,445 509,763 139,682
Net income (loss) attributable to non-controlling interest 130,762 56,613 379,796 121,208
Net income (loss) attributable to Viper Energy Partners LP $ 79,340 $ 16,832 $ 129,967 $ 18,474
Net income (loss) attributable to common limited partner units:
Basic $ 1.06 $ 0.26 $ 1.70 $ 0.28
Diluted $ 1.06 $ 0.26 $ 1.70 $ 0.28
Weighted average number of common limited partner units outstanding:
Basic 74,943 64,152 76,215 64,724
Diluted 74,943 64,241 76,325 64,815


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(In thousands, except per unit amounts)
Operating income:
Royalty income	$	195,614	$	219,909	$	514,896	$	651,828
Lease bonus income—related party	97,237		372		105,585		6,652
Lease bonus income	196		1,125		1,730		3,856

Other operating income	193		211		774		506
Total operating income	293,240		221,617		622,985		662,842
Costs and expenses:
Production and ad valorem taxes	12,286		15,638		37,794		45,547

Depletion	36,280		30,460		101,331		89,833

General and administrative expenses	1,880		2,139		6,652		5,972

Total costs and expenses	50,446		48,237		145,777		141,352
Income (loss) from operations	242,794		173,380		477,208		521,490
Other income (expense):
Interest expense, net	(11,203)		(10,731)		(32,180)		(30,158)


Gain (loss) on derivative instruments, net	(2,988)		882		(30,685)		(19,366)

Other income, net	489		162		802		200
Total other expense, net	(13,702)		(9,687)		(62,063)		(49,324)
Income (loss) before income taxes	229,092		163,693		415,145		472,166
Provision for (benefit from) income taxes	21,879		(46,409)		39,735		(37,597)
Net income (loss)	207,213		210,102		375,410		509,763
Net income (loss) attributable to non-controlling interest	128,614		130,762		232,294		379,796
Net income (loss) attributable to Viper Energy Partners LP	$	78,599	$	79,340	$	143,116	$	129,967

Net income (loss) attributable to common limited partner units:
Basic	$	1.11	$	1.06	$	1.99	$	1.70
Diluted	$	1.11	$	1.06	$	1.99	$	1.70
Weighted average number of common limited partner units outstanding:
Basic	70,925		74,943		71,803		76,215
Diluted	70,925		74,943		71,803		76,325

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Changes to Unitholders' Equity

(Unaudited)

Limited Partners General Partner Non-Controlling Interest
Common Class B Amount Amount
Units Amount Units Amount Total
(In thousands)
Balance at December 31, 2021 78,546 $ 813,161 90,710 $ 931 $ 729 $ 1,418,007 $ 2,232,828
Unit-based compensation — 284 — — — — 284
Distribution equivalent rights payments — (64) — — — — (64)
Distributions to public — (35,830) — — — — (35,830)
Distributions to Diamondback — (344) — (25) — (42,634) (43,003)
Distributions to General Partner — — — — (20) — (20)
Change in ownership of consolidated subsidiaries, net — 14,195 — — — (14,195) —
Repurchased units as part of unit buyback (1,580) (39,260) — — — — (39,260)
Net income (loss) — 16,605 — — — 111,436 128,041
Balance at March 31, 2022 76,966 768,747 90,710 906 709 1,472,614 2,242,976
Unit-based compensation — 335 — — — — 335
Distribution equivalent rights payments — (113) — — — — (113)
Distributions to public — (51,077) — — — — (51,077)
Distributions to Diamondback — (490) — (25) — (63,497) (64,012)
Distributions to General Partner — — — — (20) — (20)
Change in ownership of consolidated subsidiaries, net — 11,523 — — — (11,523) —
Repurchased units as part of unit buyback (1,020) (28,949) — — — — (28,949)
Net income (loss) — 34,022 — — — 137,598 171,620
Balance at June 30, 2022 75,946 733,998 90,710 881 689 1,535,192 2,270,760
Unit-based compensation — 362 — — — — 362
Vesting of restricted stock units 28 — — — — — —
Distribution equivalent rights payments — (132) — — — — (132)
Distributions to public — (59,901) — — — — (59,901)
Distributions to Diamondback — (593) — (24) — (78,918) (79,535)
Distributions to General Partner — — — — (20) — (20)
Change in ownership of consolidated subsidiaries, net — 20,046 — — — (20,046) —
Repurchased units as part of unit buyback (1,818) (50,723) — — — — (50,723)
Net income (loss) — 79,340 — — — 130,762 210,102
Balance at September 30, 2022 74,156 $ 722,397 90,710 $ 857 $ 669 $ 1,566,990 $ 2,290,913


	Limited Partners						General Partner		Non-Controlling Interest
	Common			Class B			Amount		Amount
	Units	Amount		Units	Amount						Total
	(In thousands)
Balance at December 31, 2022	73,230	$	689,178	90,710	$	832	$	649	$	1,630,866	$	2,321,525

Unit-based compensation	—	370		—	—		—		—		370
Vesting of restricted stock units	4	—		—	—		—		—		—
Distribution equivalent rights payments	—	(72)		—	—		—		—		(72)
Distributions to public	—	(35,253)		—	—		—		—		(35,253)
Distributions to Diamondback	—	(358)		—	(25)		—		(48,983)		(49,366)
Distributions to General Partner	—	—		—	—		(20)		—		(20)
Change in ownership of consolidated subsidiaries, net	—	11,449		—	—		—		(11,449)		—

Repurchased units as part of unit buyback	(1,115)	(33,022)		—	—		—		—		(33,022)
Net income (loss)	—	33,967		—	—		—		54,299		88,266
Balance at March 31, 2023	72,119	666,259		90,710	807		629		1,624,733		2,292,428

Unit-based compensation	—	259		—	—		—		—		259

Distribution equivalent rights payments	—	(43)		—	—		—		—		(43)
Distributions to public	—	(23,513)		—	—		—		—		(23,513)
Distributions to Diamondback	—	(241)		—	(25)		—		(38,097)		(38,363)
Distributions to General Partner	—	—		—	—		(20)		—		(20)
Change in ownership of consolidated subsidiaries, net	—	16,749		—	—		—		(16,749)		—

Repurchased units as part of unit buyback	(912)	(24,509)		—	—		—		—		(24,509)
Net income (loss)	—	30,550		—	—		—		49,381		79,931
Balance at June 30, 2023	71,207	665,511		90,710	782		609		1,619,268		2,286,170

Unit-based compensation	—	362		—	—		—		—		362
Vesting of restricted stock units	20	—		—	—		—		—		—
Distribution equivalent rights payments	—	(48)		—	—		—		—		(48)
Distributions to public	—	(25,252)		—	—		—		—		(25,252)
Distributions to Diamondback	—	(263)		—	(25)		—		(39,912)		(40,200)
Distributions to General Partner	—	—		—	—		(20)		—		(20)
Change in ownership of consolidated subsidiaries, net	—	3,469		—	—		—		(3,469)		—
Repurchased units as part of unit buyback	(365)	(9,650)		—	—		—		—		(9,650)
Net income (loss)	—	78,599		—	—		—		128,614		207,213
Balance at September 30, 2023	70,862	$	712,728	90,710	$	757	$	589	$	1,704,501	$	2,418,575

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

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

(Unaudited)


		Limited Partners						General Partner				Non-Controlling Interest										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, 2020		65,817	$	633,415	90,710	$	1,031			$	809			$	1,225,578					$	1,860,833

Balance at December 31, 2021																				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	—	315		—	—		—				—					315			Unit-based compensation		—		284			—		—		—			—		284

Vesting of restricted stock units		3	—		—	—		—				—					—
Distribution equivalent rights payments	Distribution equivalent rights payments	—	(24)		—	—		—				—					(24)			Distribution equivalent rights payments		—		(64)			—		—		—			—		(64)
Distributions to public	Distributions to public	—	(9,036)		—	—		—				—					(9,036)			Distributions to public		—		(35,830)			—		—		—			—		(35,830)
Distributions to Diamondback	Distributions to Diamondback	—	(102)		—	(25)		—				(12,699)					(12,826)			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	—	2,687		—	—		—				(2,687)					—			Change in ownership of consolidated subsidiaries, net		—		14,195			—		—		—			(14,195)		—
Cash paid for tax withholding on vested common units		—	(20)		—	—		—				—					(20)

Repurchased units as part of unit buyback	Repurchased units as part of unit buyback	(870)	(13,043)		—	—		—				—					(13,043)			Repurchased units as part of unit buyback		(1,580)		(39,260)			—		—		—			—		(39,260)
Net income (loss)	Net income (loss)	—	(3,020)		—	—		—				26,879					23,859			Net income (loss)		—		16,605			—		—		—			111,436		128,041
Balance at March 31, 2021		64,950	611,172		90,710	1,006		789				1,237,071					1,850,038

Balance at March 31, 2022																				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	—	338		—	—		—				—					338			Unit-based compensation		—		335			—		—		—			—		335

Distribution equivalent rights payments	Distribution equivalent rights payments	—	(55)		—	—		—				—					(55)			Distribution equivalent rights payments		—		(113)			—		—		—			—		(113)
Distributions to public	Distributions to public	—	(15,992)		—	—		—				—					(15,992)			Distributions to public		—		(51,077)			—		—		—			—		(51,077)
Distributions to Diamondback	Distributions to Diamondback	—	(183)		—	(25)		—				(22,678)					(22,886)			Distributions to Diamondback		—		(490)			—		(25)		—			(63,497)		(64,012)
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	—	1,614		—	—		—				(1,614)					—			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	(404)	(6,779)			—		—				—					(6,779)			Repurchased units as part of unit buyback		(1,020)		(28,949)					—		—			—		(28,949)
Net income (loss)	Net income (loss)	—	4,662		—	—		—				37,716					42,378			Net income (loss)		—		34,022			—		—		—			137,598		171,620
Balance at June 30, 2021		64,546	594,777		90,710	981		769				1,250,495					1,847,022
Balance at June 30, 2022																				Balance at June 30, 2022		75,946		733,998			90,710		881		689			1,535,192		2,270,760

Unit-based compensation	Unit-based compensation	—	243		—	—		—				—					243			Unit-based compensation		—		362			—		—		—			—		362
Vesting of restricted stock units	Vesting of restricted stock units	50	—		—	—		—				—					—			Vesting of restricted stock units		28		—			—		—		—			—		—
Distribution equivalent rights payments	Distribution equivalent rights payments	—	(62)		—	—		—				—					(62)			Distribution equivalent rights payments		—		(132)			—		—		—			—		(132)
Distributions to public	Distributions to public	—	(20,933)		—	—		—				—					(20,933)			Distributions to public		—		(59,901)			—		—		—			—		(59,901)
Distributions to Diamondback	Distributions to Diamondback	—	(240)		—	(25)		—				(29,936)					(30,201)			Distributions to Diamondback		—		(593)			—		(24)		—			(78,918)		(79,535)
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	—	4,115		—	—		—				(4,115)					—			Change in ownership of consolidated subsidiaries, net		—		20,046			—		—		—			(20,046)		—
Repurchased units as part of unit buyback	Repurchased units as part of unit buyback	(765)	(13,740)		—	—		—				—					(13,740)			Repurchased units as part of unit buyback		(1,818)		(50,723)			—		—		—			—		(50,723)
Net income (loss)	Net income (loss)	—	16,832		—	—		—				56,613					73,445			Net income (loss)		—		79,340			—		—		—			130,762		210,102
Balance at September 30, 2021		63,831	$	580,992	90,710	$	956	$	749			$	1,273,057				$	1,855,754

Balance at September 30, 2022																				Balance at September 30, 2022		74,156		$	722,397		90,710		$	857	$	669		$	1,566,990	$	2,290,913

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Cash Flows

(Unaudited)

Nine Months Ended September 30,
2022 2021
(In thousands)
Cash flows from operating activities:
Net income (loss) $ 509,763 $ 139,682
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes (49,656) —
Depletion 89,833 74,230
(Gain) loss on derivative instruments, net 19,366 70,649
Net cash receipts (payments) on derivatives (27,292) (61,188)
Other 4,372 3,332
Changes in operating assets and liabilities:
Royalty income receivable (25,647) (14,923)
Royalty income receivable—related party (8,123) (20,024)
Accounts payable and accrued liabilities 3,612 7,902
Other (2,987) 12
Net cash provided by (used in) operating activities 513,241 199,672
Cash flows from investing activities:
Acquisitions of oil and natural gas interests (38,334) (6,728)
Proceeds from sale of oil and natural gas interests 57,945 —
Net cash provided by (used in) investing activities 19,611 (6,728)
Cash flows from financing activities:
Proceeds from borrowings under credit facility 229,000 87,000
Repayment on credit facility (288,000) (79,000)
Repayment of senior notes (48,963) —
Repurchased units as part of unit buyback (118,932) (33,562)
Distributions to public (147,117) (46,102)
Distributions to Diamondback (186,550) (65,913)
Other (122) (2,948)
Net cash provided by (used in) financing activities (560,684) (140,525)
Net increase (decrease) in cash and cash equivalents (27,832) 52,419
Cash, cash equivalents and restricted cash at beginning of period 39,448 19,121
Cash, cash equivalents and restricted cash at end of period $ 11,616 $ 71,540


	Nine Months Ended September 30,
	2023		2022
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	375,410	$	509,763
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes	887		(49,656)
Depletion	101,331		89,833

(Gain) loss on derivative instruments, net	30,685		19,366
Net cash receipts (payments) on derivatives	(10,019)		(27,292)






Other	2,045		4,372
Changes in operating assets and liabilities:

Royalty income receivable	(22,147)		(25,647)
Royalty income receivable—related party	(1,171)		(8,123)


Accounts payable and accrued liabilities	4,156		3,612

Accounts payable—related party	(306)		—
Income tax payable	12,411		(471)

Other	(885)		(2,516)
Net cash provided by (used in) operating activities	492,397		513,241
Cash flows from investing activities:

Acquisitions of oil and natural gas interests—related party	(75,073)		—
Acquisitions of oil and natural gas interests	(98,510)		(38,334)



Proceeds from sale of oil and natural gas interests	(3,166)		57,945


Net cash provided by (used in) investing activities	(176,749)		19,611
Cash flows from financing activities:
Proceeds from borrowings under credit facility	260,000		229,000
Repayment on credit facility	(162,000)		(288,000)

Repayment of senior notes	—		(48,963)








Repurchased units as part of unit buyback	(67,181)		(118,932)
Distributions to public	(84,181)		(147,117)
Distributions to Diamondback	(127,929)		(186,550)
Other	(5,722)		(122)
Net cash provided by (used in) financing activities	(187,013)		(560,684)
Net increase (decrease) in cash and cash equivalents	128,635		(27,832)
Cash, cash equivalents and restricted cash at beginning of period	18,179		39,448
Cash, cash equivalents and restricted cash at end of period	$	146,814	$	11,616

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 September 30, ~~2022,~~2023, Viper Energy Partners GP LLC (the “General Partner”) held a 100% general partner interest in the Partnership and Diamondback Energy, Inc. ~~(“Diamondback”~~and its subsidiary, Diamondback E&P LLC (collectively, “Diamondback”) beneficially owned approximately ~~55%~~57% of thethe Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner.

Basis of Presentation

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

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

Reclassifications

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, the ~~effects of COVID-19, the~~ war in Ukraine and ~~actions by OPEC members~~the Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, and ~~other exporting nations on~~measures to combat persistent inflation and instability in the ~~supply~~financial sector have contributed to recent pricing 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 and may continue to be 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 interests, the recoverability of costs of unevaluated properties, the fair value determination of assets and liabilities, including

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests, estimates of third party operated royalty income related to expected sales volumes and prices, 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, including deferred tax valuation allowances.

Related Party Transactions

Royalty Income Receivable

As of September 30, 2023 and December 31, 2022, Diamondback, either directly or through its consolidated subsidiaries, owed the Partnership $7.4 million and $6.3 million, respectively, for royalty income received from third parties for the Partnership’s production, which had not yet been remitted to the Partnership.

Lease Bonus Income

During the three and nine months ended September 30, 2023 and 2022, Diamondback ~~either directly or through its consolidated subsidiaries,~~ paid the Partnership $97.2 million, $105.6 million, $0.4 million and $6.7 million, respectively, of lease bonus income primarily related to ~~certain~~new leases ~~acquired~~ in the ~~Swallowtail Acquisition.~~Permian Basin. Lease bonus income for the three and nine months ended September 30, 2023 includes a lease bonus payment of $95.8 million to the Operating Company from a lease agreement with a subsidiary of Diamondback covering certain Permian Basin acreage on terms substantially identical to the Operating Company’s other lease arrangements with Diamondback. This transaction was considered and approved by the conflicts committee of the board of directors of the General Partner. Subsequent to September 30, 2023, we used $95.8 million in lease bonus proceeds to reduce amounts outstanding under the Operating Company’s revolving credit facility.

See Note 4—Acquisitions and Divestitures for significant related party acquisitions of oil and natural gas interests. All other significant related party transactions with Diamondback or its affiliates have been stated on the face of the condensed consolidated financial statements ~~included elsewhere in this report~~ as of September 30, ~~2022~~2023 and for the three and nine months ended September 30, ~~2022~~2023 and ~~2021.~~2022.

Accrued Liabilities

Accrued liabilities consist of the following:


		September 30,		December 31,			September 30,		December 31,
		2022		2021			2023		2022
		(In thousands)					(In thousands)
Interest payable	Interest payable	$	9,694	$	4,430	Interest payable	$	10,348	$	3,972
Ad valorem taxes payable	Ad valorem taxes payable	11,075		6,201		Ad valorem taxes payable	12,357		12,492
Derivatives instruments payable	Derivatives instruments payable	2,252		8,879		Derivatives instruments payable	807		1,684
Other	Other	1,152		999		Other	1,176		1,452
Total accrued liabilities	Total accrued liabilities	$	24,173	$	20,509	Total accrued liabilities	$	24,688	$	19,600

Recent Accounting Pronouncements

Recently Adopted Pronouncements

There are no recently adopted 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.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(In thousands)
Oil income	$	168,008	$	167,934	$	443,927	$	514,180
Natural gas income	8,893		28,638		22,974		67,621
Natural gas liquids income	18,713		23,337		47,995		70,027
Total royalty income	$	195,614	$	219,909	$	514,896	$	651,828

4. ACQUISITIONS AND DIVESTITURES

2023 Activity

Drop Down Transaction

On March 8, 2023, the Partnership completed the acquisition of certain mineral and royalty interests from subsidiaries of Diamondback for approximately $74.5 million in cash, including customary post-closing adjustments for net title benefits (the ‘‘Drop Down’’). The mineral and royalty interests acquired in the Drop Down represent approximately 660 net royalty acres in Ward County in the Southern Delaware Basin, 100% of which are operated by Diamondback, and have an average net royalty interest of approximately 7.2% and current production of approximately 300 BO/d. The Partnership funded the Drop Down through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. The Drop Down was accounted for as a transaction between entities under common control with the properties acquired recorded at Diamondback’s historical carrying value in the Partnership’s condensed consolidated balance sheet. The historical carrying value of the properties approximated the Drop Down purchase price.

Other Acquisitions

During the nine months ended September 30, 2023, the Partnership acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 213 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $48.9 million, subject to customary post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

Upon entering into an agreement for the Acquisition (as further discussed and defined in Note 13—Subsequent Events) in September 2023, the Partnership deposited $50.0 million of the purchase price in an escrow account, which is included in the captions “Funds held in escrow” on the condensed consolidated balance sheet and “Acquisitions of oil and natural gas interest” on the condensed consolidated statement of cash flows at September 30, 2023.

2022 Activity

Acquisitions

During the year ended December 31, 2022, in individually insignificant transactions, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests representing 375 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $65.8 million, including certain customary post-closing adjustments. The

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(In thousands)
Oil income $ 167,934 $ 100,154 $ 514,180 $ 272,450
Natural gas income 28,638 12,074 67,621 30,651
Natural gas liquids income 23,337 15,421 70,027 34,518
Total royalty income $ 219,909 $ 127,649 $ 651,828 $ 337,619

~~4. ACQUISITIONS AND DIVESTITURES~~

~~2022 Activity~~

~~Acquisitions~~

In the third quarter of 2022, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests representing 165 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $40.1 million, subject to post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

Divestitures

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 aan aggregate net sales price of $29.3 million, including ~~post-closing~~customary closing adjustments.

In the third quarter of 2022, the Partnership divested 93 net royalty acres of third party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate net sales price of $29.9 million, ~~subject to~~including customary closing adjustments.

~~2021 Activity~~In the fourth quarter of 2022, the Partnership divested its entire position in the Eagle Ford Shale consisting of 681 net royalty acres of third party operated acreage for an aggregate net sales price of $53.7 million, including customary closing adjustments.

~~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% were operated by Diamondback as of December 31, 2021. The Swallowtail Acquisition has an effective date of August 1, 2021. In accordance with the terms of the purchase agreement, the Partnership deposited $30.0 million into an escrow account in August 2021, which was released upon the closing of the transaction in October 2021. The cash portion of this transaction was funded through a combination of cash on hand and approximately $190.0 million of borrowings under the Operating Company’s revolving credit facility.

~~Other 2021 Acquisitions~~

Additionally during the year ended December 31, 2021, the Partnership acquired, from unrelated third party sellers, mineral and royalty interests representing 1,277 gross (392 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $55.1 million, after post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

~~Table of Contents~~

~~Viper Energy Partners LP~~

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

~~(Unaudited)~~

5. OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:


		September 30,		December 31,			September 30,		December 31,
		2022		2021			2023		2022
		(In thousands)					(In thousands)
Oil and natural gas interests:	Oil and natural gas interests:					Oil and natural gas interests:
Subject to depletion	Subject to depletion	$	2,033,235	$	1,873,418	Subject to depletion	$	2,441,057	$	2,167,598
Not subject to depletion	Not subject to depletion	1,460,744		1,640,172		Not subject to depletion	1,151,711		1,297,221
Gross oil and natural gas interests	Gross oil and natural gas interests	3,493,979		3,513,590		Gross oil and natural gas interests	3,592,768		3,464,819
Accumulated depletion and impairment	Accumulated depletion and impairment	(688,996)		(599,163)		Accumulated depletion and impairment	(821,565)		(720,234)
Oil and natural gas interests, net	Oil and natural gas interests, net	2,804,983		2,914,427		Oil and natural gas interests, net	2,771,203		2,744,585
Land	Land	5,688		5,688		Land	5,688		5,688
Property, net of accumulated depletion and impairment	Property, net of accumulated depletion and impairment	$	2,810,671	$	2,920,115	Property, net of accumulated depletion and impairment	$	2,776,891	$	2,750,273

As of September 30, ~~2022~~2023 and December 31, ~~2021,~~2022, the Partnership had mineral and royalty interests representing ~~26,789~~27,189 and ~~27,027~~26,315 net royalty acres, respectively.

No impairment expense was recorded on the Partnership’s oil and natural gas interests for the three and nine months ended September 30, ~~2022~~2023 and ~~2021~~2022 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:~~

September 30, December 31,
2022 2021
(In thousands)
5.375% senior unsecured notes due 2027 $ 430,350 $ 479,938
Revolving credit facility 245,000 304,000
Unamortized debt issuance costs (1,374) (1,757)
Unamortized discount (4,338) (5,454)
Total long-term debt $ 669,638 $ 776,727

~~Repurchases of Notes~~

During the nine months ended September 30, 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 nine months ended September 30, 2022 after including accrued interest and the write-off of related unamortized costs. 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 September 30, 2022, the Operating Company had elected a commitment amount of $500.0 million, with~~

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6. DEBT

~~$245.0~~

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


	September 30,		December 31,
	2023		2022
	(In thousands)
5.375% Senior unsecured notes due 2027	$	430,350	$	430,350

Revolving credit facility	250,000		152,000
Unamortized debt issuance costs	(1,104)		(1,306)
Unamortized discount	(3,565)		(4,149)
Total long-term debt	$	675,681	$	576,895

The Operating Company’s Revolving Credit Facility

On September 22, 2023, the Operating Company entered into an eleventh and separately a twelfth amendment to the existing credit agreement, which among other things, (i) extended the maturity date from June 2, 2025, to September 22, 2028, (ii) maintained the maximum credit amount of $2.0 billion, (iii) increased the borrowing base from $1.0 billion to $1.3 billion upon consummation of the Acquisition (as defined in Note 13—Subsequent Events), (iv) increased the aggregate elected commitment amount from $750.0 million to $850.0 million, and (v) waived the automatic reduction of the borrowing base that otherwise would have occurred upon the consummation of the issuance of the 2031 Notes (as defined in Note 13—Subsequent Events). The borrowing base is scheduled to be redetermined semi-annually in May and November. As of September 30, 2023, the Operating Company had $250.0 million of outstanding borrowings and ~~$255.0~~$600.0 million available for future borrowings. During the three and nine months ended September 30, ~~2022~~2023 and ~~2021~~2022, the weighted average interest rates on the Operating Company’s revolving credit ~~facility~~facility were 7.58%, 7.37%, 4.75%, and 3.53%~~, 1.98% and 2.14%~~, respectively.~~The revolving credit facility will mature on June 2, 2025.~~

As of September 30, ~~2022,~~2023, the Operating Company waswas in compliance with the financial maintenance covenants under its credit agreement.

7. UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has General Partner and limited partner units. At September 30, ~~2022,~~2023, the Partnership had a total of ~~74,156,051~~70,861,557 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%~~57% of the Partnership’s total limited partner units outstanding. At September 30, ~~2022,~~2023, Diamondback also beneficially ~~owns~~owned 90,709,946 Operating Company units, representing a ~~55%~~56% non-controlling ownership interest in the Operating Company. The Operating Company units and the Partnership’s Class B units beneficially owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

See Note 13—Subsequent Events for further discussion of additional common units issued in the fourth quarter of 2023.

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 $750.0 million of the Partnership’s outstanding common units, excluding excise tax, 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 nine months ended September 30, ~~2022~~2023 and ~~2021,~~2022, the Partnership repurchased, excluding excise tax, approximately $9.6 million, $66.5 million, $50.7 million ~~$118.9 million, $13.7 million~~ and ~~$33.6~~$118.9 million of common units under the repurchase program, respectively. Repurchases for the nine months ended September 30, 2022 ~~include~~included approximately $37.3 million for the repurchase of 1.5 million common units from a significant unitholder in a privately negotiated transaction

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in the first quarter of 2022. As of September 30, ~~2022, $561.0~~2023, $462.9 million remains available ~~for use to repurchase common units~~ under the repurchase ~~program.~~program, excluding excise tax.

Cash Distributions ~~on Common Units~~

~~The~~Effective with the Partnership’s distribution payable for the third quarter of 2022, the board of directors of the General Partner ~~has established~~approved a distribution policy ~~whereby the Operating Company distributes all or~~consisting of a ~~portion of its available cash on a quarterly basis~~base and variable distribution that takes into account capital returned 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~~via our common ~~unitholders.~~unit repurchase program. The Partnership’s available cash and the available cash of the Operating Company for each quarter is determined by the board of directors of the General Partner following the end of such quarter. The cash available for distribution by the Operating Company, a non-GAAP measure, generally equals the Partnership’s consolidated Adjusted EBITDA for the applicable quarter, less cash needed for income taxes payable, debt service, 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, lease bonus income, distribution equivalent rights payments and preferred distributions, if any. The ~~Partnership’s cash available for distribution for each quarter generally equals~~board approved the ~~Partnership’s proportional share~~exclusion of ~~the cash distributed by the Operating Company~~lease bonus income, net of applicable taxes, effective for the ~~quarter, less cash needed by the Partnership for the payment of income taxes, if any, and the preferred distribution. Further, in July 2022, the board of directors of the General Partner approved~~distribution to be paid on November 24, 2023. For a distribution policy, effective beginning with the Partnership’s distribution payable for the third quarter of 2022, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our common unit repurchase program. The board updated the distribution policy in November 2022, providing that lease bonus payments and other similar, one-time, non-recurring payments will be excluded from the calculationdetailed description of the Partnership’s and the Operating Company’s ~~available cash.~~distribution policy, see Note 7—Unitholders’ Equity and Distributions—Cash Distributions in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2022.

The percentage of cash available for distribution pursuant to the distribution policy ~~discussed above~~ may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet while also expanding the return of capital program through the Partnership’s common unit repurchase program. Effective July 25, 2023, the board of directors of the General Partner approved an increase to the Partnership’s annual base distribution to $1.08 per common unit beginning with the distribution paid for the second quarter of 2023. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other basis.

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The following table presents information regarding cash distributions approved by the board of directors of the General Partner for the periods presented (in thousands, except for per ~~share~~unit amounts):

Period Amount per Operating Company Unit Operating Company Distributions to Diamondback Amount per Common Unit
Distributions to Common Unitholders(1)
Declaration Date Unitholder Record Date Payment Date
Q4 2021 $ 0.47 $ 42,634 $ 0.47 $ 36,238 February 16, 2022 March 4, 2022 March 11, 2022
Q1 2022 $ 0.70 $ 63,497 $ 0.67 $ 51,680 April 27, 2022 May 12, 2022 May 19, 2022
Q2 2022 $ 0.87 $ 78,918 $ 0.81 $ 60,626 July 26, 2022 August 16, 2022 August 23, 2022




Period	Amount per Operating Company Unit		Operating Company Distributions to Diamondback		Amount per Common Unit		Distributions to Common Unitholders(1)		Declaration Date	Unitholder Record Date	Payment Date
Q4 2022	$	0.54	$	48,983	$	0.49	$	35,683	February 15, 2023	March 3, 2023	March 10, 2023
Q1 2023	$	0.42	$	38,097	$	0.33	$	23,797	April 26, 2023	May 11, 2023	May 18, 2023
Q2 2023	$	0.44	$	39,912	$	0.36	$	25,563	July 25, 2023	August 10, 2023	August 17, 2023

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

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

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Change in Ownership of Consolidated Subsidiaries

Non-controlling interest in the accompanying condensed consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. Diamondback’s relative ownership interest in the Operating Company can change due to the Partnership’s public offerings of units, 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 September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(In thousands)
Net income (loss) attributable to the Partnership $ 79,340 $ 16,832 $ 129,967 $ 18,474
Change in ownership of consolidated subsidiaries 20,046 4,115 45,764 8,416
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest $ 99,386 $ 20,947 $ 175,731 $ 26,890

~~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 December 31, 2022. These special income allocations reduce the taxable income allocated to the Partnership’s common unitholders.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(In thousands)
Net income (loss) attributable to the Partnership	$	78,599	$	79,340	$	143,116	$	129,967

Change in ownership of consolidated subsidiaries	3,469		20,046		31,667		45,764




Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest	$	82,068	$	99,386	$	174,783	$	175,731

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) attributable to the Partnership’s common units for the three and nine months ended September 30, ~~2022~~2023 and ~~2021.~~

2022. The Partnership’s net income (loss) is allocated wholly to the common units, as the General Partner does not have an economic interest.

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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(In thousands, except per unit amounts)
Net income (loss) attributable to the period	$	78,599	$	79,340	$	143,116	$	129,967
Less: distributed and undistributed earnings allocated to participating securities(1)	146		173		263		309
Net income (loss) attributable to common unitholders	$	78,453	$	79,167	$	142,853	$	129,658
Weighted average common units outstanding:
Basic weighted average common units outstanding	70,925		74,943		71,803		76,215
Effect of dilutive securities:
Potential common units issuable(2)	—		—		—		110
Diluted weighted average common units outstanding	70,925		74,943		71,803		76,325
Net income (loss) per common unit, basic	$	1.11	$	1.06	$	1.99	$	1.70
Net income (loss) per common unit, diluted	$	1.11	$	1.06	$	1.99	$	1.70

(1) Unvested restricted stock units that contain non-forfeitable distribution equivalent rights granted are considered participating securities and therefore are included in the earnings per unit calculation pursuant to the two-class method.

(2) For the three and nine months ended September 30, 2023 and 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.

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~~A reconciliation of~~

As discussed further in Note 13—Subsequent Events“—Recent Acquisition,” the ~~components of basic and diluted earnings per~~Partnership issued approximately 7.22 million common units to Diamondback under the common unit ~~is presented~~purchase agreement and 9.02 million additional common units as consideration for the Acquisition in the ~~table below:~~

Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(In thousands, except per unit amounts)
Net income (loss) attributable to the period $ 79,340 $ 16,832 $ 129,967 $ 18,474
Less: net income (loss) allocated to participating securities(1)
(173) (62) (309) (141)
Net income (loss) attributable to common unitholders $ 79,167 $ 16,770 $ 129,658 $ 18,333
Weighted average common units outstanding:
Basic weighted average common units outstanding 74,943 64,152 76,215 64,724
Effect of dilutive securities:
Potential common units issuable(2)
— 89 110 91
Diluted weighted average common units outstanding 74,943 64,241 76,325 64,815
Net income (loss) per common unit, basic $ 1.06 $ 0.26 $ 1.70 $ 0.28
Net income (loss) per common unit, diluted $ 1.06 $ 0.26 $ 1.70 $ 0.28

~~(1) Restricted stock units with non-forfeitable distribution equivalent rights granted to employees are considered participating securities.~~

~~(2) For the three and nine months ended September 30, 2022, and the three months ended September 30, 2021,there were no potential common units excluded from the computation~~fourth quarter of diluted earnings per common unit because their inclusion would have been anti-dilutive. For the nine months ended September 30, 2021, 2,955 potential common units were excluded in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive.2023.

9. INCOME TAXES

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


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2022			2021			2022			2021				2023			2022			2023			2022
		(In thousands, except for tax rate)													(In thousands, except for tax rate)
Provision for (benefit from) income taxes	Provision for (benefit from) income taxes	$	(46,409)		$	906		$	(37,597)		$	941		Provision for (benefit from) income taxes	$	21,879		$	(46,409)		$	39,735		$	(37,597)
Effective tax rate	Effective tax rate	(28.4)		%	1.2		%	(8.0)		%	0.7		%	Effective tax rate	9.6		%	(28.4)		%	9.6		%	(8.0)		%

The Partnership’s effective income tax ~~rates~~rate for the three and nine months ended September 30, 2023 differed from the amount 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. The Partnership’s effective income tax rate for the three and nine months ended September 30, 2022 differed from ~~amounts~~the amount 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. During the three months ended September 30, 2022, the Partnership recognized a discrete income tax benefit of $49.7 million related to a partial release of its beginning-of-the-year valuation allowance, based on a change in judgment about the realizability of its deferred tax assets in future years. Management’s assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets as required by applicable accounting standards, resulted in recognition of tax benefit for the portion of the Partnership’s deferred tax assets considered more likely than not to be realized. The positive evidence assessed included recent cumulative income due in part to higher commodity prices and an expectation of future taxable income based upon recent actual and forecasted production volumes and prices. The Partnership retained a partial valuation allowance on its deferred tax assets due in part to potential future volatility in commodity prices impacting the likelihood of future realizability. As of September 30, 2022, the Partnership had a deferred tax asset of $152.7 million offset by an allowance of $103.0 million.

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The Partnership’s effective income tax rates for the three and nine months ended September 30, 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 September 30, ~~2021,~~2023 and 2022, the Partnership maintained a ~~full~~partial valuation allowance against its deferred tax assets considered not more likely than not to be realized, based on its assessment of all available evidence, both positive and negative ~~supporting realizability of the Partnership’s deferred tax assets.~~as required by applicable accounting standards.

The ~~CHIPS and Science Act of 2022 (“CHIPS”) was enacted on August 9, 2022, and the~~ Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, ~~which created a 15% corporate alternative minimum~~and imposed an excise tax of 1% on ~~profits~~the fair market value of ~~corporations whose average financial statement income exceeds $1 billion,~~certain public company stock/unit repurchases for tax years beginning after December 31, 2022, and included several other provisions applicable to U.S. income taxes for corporations.The ~~Partnership considered~~Partnership’s excise tax during the ~~impact~~three and nine months ended September 30, 2023 was immaterial and is recognized as part of ~~this legislation in~~ the ~~period~~cost basis of ~~enactment and concluded there was not a material impact to~~ the ~~Partnership’s current or deferred income tax balances.~~units repurchased.

10. DERIVATIVES

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

Commodity Contracts

The Partnership historically has used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At September 30, ~~2022,~~2023, the Partnership has put options, costless collars ~~put options~~ and fixed price basis swaps outstanding.

The Partnership’s derivative contracts are based upon reported settlement prices on commodity exchanges, with put contracts for oil based on WTI Cushing and fixed price basis swaps for oil based on the spread between the WTI Cushing crude oil price and the Argus WTI Midland crude oil price. The Partnership’s fixed price basis swaps for natural gas are for the spread between the Waha Hub natural gas price and the Henry Hub natural gas price. The weighted average differential represents the amount of reduction to the WTI Cushing oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts. 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

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when the settlement price is above the ceiling price, the Partnership is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

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

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

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

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As of September 30, ~~2022,~~2023, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

Swaps Collars Puts
Settlement Month Settlement Year Type of Contract Bbls/Mcf Per Day Index Weighted Average Differential Weighted Average Floor Price Weighted Average Ceiling Price Strike Price
OIL
Oct. - Dec. 2022 Collars 4,000 WTI Cushing $— $50.00 $128.01 $—
Oct. - Dec. 2022
Puts(1)
8,000 WTI Cushing $— $— $— $55.00
Jan. - Mar. 2023
Puts(2)
8,000 WTI Cushing $— $— $— $54.25
Jan. - Dec. 2023
Basis Swap(3)
2,000 Argus WTI Midland $0.95 $— $— $—
NATURAL GAS
Oct. - Dec. 2022 Collars 20,000 Henry Hub $— $2.50 $4.62 $—
Jan. - Dec. 2023
Basis Swap(3)
30,000 Waha Hub $(1.33) $— $— $—

~~(1) Includes a deferred premium at a weighted average price of $1.54/Bbl.~~

~~(2) Includes a deferred premium at a weighted average price of $1.90/Bbl.~~

(3) The Partnership has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as 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 Cushing, Oklahoma oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.


					Swaps	Collars		Puts
Settlement Month	Settlement Year	Type of Contract	Bbls/MMBtu Per Day	Index	Weighted Average Differential	Weighted Average Floor Price	Weighted Average Ceiling Price	Strike Price	Deferred Premium
OIL
Oct. - Dec.	2023	Puts	16,000	WTI Cushing	$—	$—	$—	$56.25	$(1.70)
Jan. - Mar.	2024	Puts	14,000	WTI Cushing	$—	$—	$—	$58.57	$(1.54)
Apr. - Jun.	2024	Puts	12,000	WTI Cushing	$—	$—	$—	$60.00	$(1.50)
Oct. - Dec.	2023	Basis Swaps	4,000	WTI Midland	$1.05	$—	$—	$—	$—
Jan. - Jun.	2024	Costless Collar	6,000	WTI Cushing	$—	$65.00	$95.55	$—	$—
NATURAL GAS
Oct. - Dec.	2023	Basis Swaps	30,000	Waha Hub	$(1.33)	$—	$—	$—	$—
Jan. - Dec.	2024	Basis Swaps	30,000	Waha Hub	$(1.20)	$—	$—	$—	$—

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.

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Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments included in the condensed consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021			2023		2022		2023		2022
		(In thousands)									(In thousands)
Gain (loss) on derivative instruments	Gain (loss) on derivative instruments	$	882	$	(9,599)	$	(19,366)	$	(70,649)	Gain (loss) on derivative instruments	$	(2,988)	$	882	$	(30,685)	$	(19,366)
Net cash receipts (payments) on derivatives(1)	Net cash receipts (payments) on derivatives(1)	$	(10,263)	$	(25,306)	$	(27,292)	$	(61,188)	Net cash receipts (payments) on derivatives(1)	$	(3,807)	$	(10,263)	$	(10,019)	$	(27,292)

(1)The three and nine months ended September 30, 2022 ~~includes~~include cash paid on commodity contracts terminated prior to their contractual maturity of $2.4 million and $6.6 million, respectively.

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

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~~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~~As discussed in Note 11—Fair Value Measurements in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2022, certain assets and liabilities are reported at fair value on a recurring basis on the Partnership’s condensed consolidated balance sheets, 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 in~~puts.~~puts in the fair value hierarchy. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Partnership’s condensed consolidated balance sheets as of September 30, ~~2022~~2023 and December 31, ~~2021.~~ ~~The net amounts are classified as current or noncurrent based on their anticipated settlement dates.~~2022:


		As of September 30, 2022													As of September 30, 2023
		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	$	—	$	9,872	$	—	$	9,872	$	(5,186)	$	4,686	Derivative instruments	$	—	$	4,616	$	—	$	4,616	$	(4,616)	$	—
Non-current:

Derivative instruments		$	—	$	1,058	$	—	$	1,058	$	(219)	$	839

Liabilities:	Liabilities:													Liabilities:
Current:	Current:													Current:
Derivative instruments	Derivative instruments	$	—	$	6,077	$	—	$	6,077	$	(5,186)	$	891	Derivative instruments	$	—	$	13,900	$	—	$	13,900	$	(4,616)	$	9,284
Non-current:	Non-current:													Non-current:
Derivative instruments	Derivative instruments	$	—	$	344	$	—	$	344	$	(219)	$	125	Derivative instruments	$	—	$	1,619	$	—	$	1,619	$	—	$	1,619

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)


		As of December 31, 2021													As of December 31, 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	$	—	$	1,921	$	—	$	1,921	$	(1,921)	$	—	Derivative instruments	$	—	$	13,296	$	—	$	13,296	$	(3,968)	$	9,328
Non-current:														Non-current:

Derivative instruments														Derivative instruments	$	—	$	1,911	$	—	$	1,911	$	(1,469)	$	442
Liabilities:	Liabilities:													Liabilities:
Current:	Current:													Current:
Derivative instruments	Derivative instruments	$	—	$	5,338	$	—	$	5,338	$	(1,921)	$	3,417	Derivative instruments	$	—	$	3,968	$	—	$	3,968	$	(3,968)	$	—

Non-current:														Non-current:
Derivative instruments														Derivative instruments	$	—	$	1,476	$	—	$	1,476	$	(1,469)	$	7

Assets and Liabilities Not Recorded at Fair Value

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


		September 30, 2022				December 31, 2021					September 30, 2023				December 31, 2022
		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	$	245,000	$	245,000	$	304,000	$	304,000	Revolving credit facility	$	250,000	$	250,000	$	152,000	$	152,000
5.375% senior notes due 2027(1)		$	424,638	$	399,180	$	472,727	$	498,992
5.375% Senior notes due 2027(1)										5.375% Senior notes due 2027(1)	$	425,681	$	409,164	$	424,895	$	411,634

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

The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was determined using the September 30, ~~2022~~2023 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 mineral and royalty interests acquired in asset acquisitions and subsequent write-downs of our proved oil and natural gas 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, funds held in escrow, other current assets, accounts payable, accrued liabilities and ~~accrued liabilities.~~income taxes payable. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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. 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

Pending Conversion into Corporation

As previously reported, on July 31, 2023, the Partnership announced its intent to convert its legal status from a Delaware limited partnership into a Delaware corporation (the “Conversion”). The Conversion was unanimously approved by the board of directors of the General Partner in November 2023. On November 2, 2023, the General Partner, on behalf of the Partnership, filed the certificate of conversion and the certificate of incorporation with the Secretary of the State of Delaware and notified Nasdaq of such filings. The Partnership anticipates that the Conversion will become effective at 12:01 a.m. (Eastern Time) on November 13, 2023. See “Management ’s Discussion and Analysis of Financial Condition and Results of Operations —Recent Developments—Pending Conversion into Corporation” for additional information regarding the Conversion.

2031 Notes Offering

On October 19, 2023, the Partnership completed an offering (the “2031 Notes Offering”) of $400.0 million in aggregate principal amount of its 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”). The Partnership received net proceeds of approximately $394.4 million, after deducting the initial purchasers’ discount and expected transactions costs, from the 2031 Notes Offering. The Partnership loaned the gross proceeds to the Operating Company, which used the proceeds to partially fund the cash portion of the Acquisition as defined and discussed further below.

The 2031 Notes are senior unsecured obligations of the Partnership, initially guaranteed on a senior unsecured basis by the Operating Company, and will pay interest semi-annually. Neither Diamondback nor the General Partner will guarantee the 2031 Notes. In the future, each of the Partnership’s restricted subsidiaries that either (i) guarantees any of its or a guarantor’s indebtedness, or (ii) is a domestic restricted subsidiary and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the 2031 Notes.

Viper Issuance of Common Units to Diamondback

On October 31, 2023, the Partnership issued approximately 7.22 million of its common units to Diamondback at a price of $27.72 per unit for total net proceeds of approximately $200.0 million pursuant to a common unit purchase and sale agreement entered into with Diamondback on September 4, 2023. The net proceeds of this common unit issuance were used to fund a portion of the cash consideration for the Acquisition, as defined and discussed further below.

Acquisition

On November 1, 2023, the Partnership and the Operating Company acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP (collectively, “the Sellers,” and affiliates of Warwick Capital Partners and GRP Energy Capital) pursuant to a definitive purchase and sale agreement for approximately 9.02 million common units and $750.0 million in cash, subject to customary post-closing adjustments (the “Acquisition”). The mineral and royalty interests acquired in the Acquisition represent approximately 4,600 net royalty acres in the Permian Basin, plus approximately 2,700 additional net royalty acres in other major basins. The cash consideration for the Acquisition was funded through a combination of cash on hand and held in escrow, borrowings under the Operating Company’s revolving credit facility, proceeds from the 2031 Notes Offering and proceeds from the $200.0 million common unit issuance to Diamondback. Following the completion of the Acquisition, Diamondback beneficially owned approximately 56% of the Partnership’s total limited partner units outstanding.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

~~13. SUBSEQUENT EVENTS~~

Cash Distribution

On November ~~3, 2022,~~2, 2023, the board of directors of the General Partner approved a cash distribution for the third quarter of ~~2022~~2023 by the Operating Company under its distribution policy of ~~$0.49~~$0.70 per ~~common~~Operating Company unit, payable on November ~~25, 2022,~~24, 2023, to eligible unitholders of record at the close of business on November ~~17, 2022.~~16, 2023.

On November 2, 2023, the board of directors of the General Partner also approved a cash distribution for the third quarter of 2023 by the Partnership under its distribution policy of $0.57 per common unit, payable on November 24, 2023, to eligible unitholders of record at the close of business on November 16, 2023. The distribution to common unitholders consists of a base quarterly distribution of ~~$0.25~~$0.27 per common unit and a variable quarterly distribution of ~~$0.24~~$0.30 per common unit.

The distribution record and payment dates will occur after the effective date of the Conversion; accordingly, Viper Energy, Inc. (“Viper Inc.”) will pay the base quarterly distribution and variable quarterly distribution to holders of Class A common stock (“Class A Common Stock”) post-Conversion under the same terms as approved by the board of directors of the General Partner.

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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.~~2022. 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.

Recent Developments

Pending Conversion into Corporation

As previously reported, on July 31, 2023, we announced our intent to convert our legal status from a Delaware limited partnership into a Delaware corporation (the “Conversion”), which we believe would further broaden our investor base and improve our trading liquidity. The Conversion was unanimously approved by the board of directors of the General Partner on November 2, 2023. Under the limited partnership agreement of the Partnership, as amended in connection with the Conversion (the “LP Agreement”), no vote of the limited partners is required or will be sought for the Conversion. On November 2, 2023, the General Partner, on behalf of the Partnership, filed the certificate of conversion and the certificate of incorporation with the Secretary of the State of Delaware and notified Nasdaq of such filings. We anticipate that the Conversion will become effective at 12:01 a.m. (Eastern Time) on November 13, 2023 (such date and time at which the Conversion becomes effective, the “Effective Time”).

At the Effective Time, the Partnership will convert into a Delaware corporation pursuant to a plan of conversion (the “Plan of Conversion”) and will change its name from Viper Energy Partners LP to Viper Inc., and the certificate of incorporation and the bylaws of Viper Inc. will become effective.

At the Effective Time, each common unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time will be converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class A Common Stock $0.000001 par value per share, of Viper Inc., (ii) each Class B unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time will be converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class B common stock, $0.000001 par value per share, of Viper Inc. (“Class B Common Stock” and, together with Class A Common Stock, “Common Stock”), and (iii) the general partner interest issued and outstanding immediately prior to the Effective Time (100% owned by the General Partner) will be cancelled and no longer outstanding at the Effective Time. At the Effective Time, as a result of the Conversion, holders of common units will become holders of Class A Common Stock and holders of Class B units will become holders of Class B Common Stock. Similar to Class B units before the Conversion, each share of Class B Common Stock will be exchangeable, at the discretion of the holders of Class B Common Stock, together with one unit of the Operating Company, into one share of Class A Common Stock post-Conversion. Holders of Class B Common Stock will have the same preferred distribution and liquidation preference rights as those provided under the LP Agreement. At the Effective Time, Diamondback and its wholly owned subsidiary Diamondback E&P LLC will be the only holders of the Class B Common Stock and will collectively own approximately 56% of the outstanding shares of Common Stock. As a result, Viper Inc. will be a “controlled company” within the meaning of the corporate governance standards of Nasdaq and, as a result, will qualify for certain exemptions from the corporate governance rules of Nasdaq.

After the Conversion, it is expected that our current limited partners will own the same percentage of Viper Inc.’s outstanding shares as they currently own of the Partnership’s outstanding equity interests.

At the Effective Time, the certificate of incorporation and bylaws of Viper Inc. will generally provide stockholders of Viper Inc. with substantially the same rights and obligations as those that limited partners had in the LP Agreement. Currently, limited partners are not generally entitled to vote with respect to governance of the Partnership under the LP Agreement, except for those few matters set forth in the LP Agreement. Following the Conversion, except as otherwise expressly provided in the Certificate of Incorporation, the holders of Common Stock will be entitled to vote on all matters on which stockholders of a

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corporation are generally entitled to vote on under the Delaware General Corporation Law, including the election of the board of directors of Viper Inc.

At the Effective Time, the business and affairs of Viper Inc. will be overseen by a board of directors of Viper Inc., rather than the General Partner, which currently oversees the business and affairs of the Partnership, as its general partner.The directors and executive officers of the General Partner immediately prior to the Effective Time will become the directors and executive officers of Viper Inc. at the Effective Time. In addition, the audit committee of the board of directors of the General Partner, and the membership thereof, immediately prior to the Effective Time, will be replicated at Viper Inc. at the Effective time. Further, post-Conversion, Diamondback will continue to provide personnel and general and administrative services to Viper Inc., including the services of the executive officers and other employees, pursuant to the services and secondment agreement in substantially the same manner as Diamondback currently provides to the General Partner. In addition, for so long as Diamondback and any of its subsidiaries collectively beneficially own at least 25% of the outstanding common stock of Viper Inc., (i) Diamondback will have the right to designate up to three persons to serve as directors of Viper Inc. and (ii) the board of directors of Viper Inc. may not appoint any person other than a Diamondback seconded employee as an executive officer of Viper Inc. unless such appointment is approved, in advance, by either (x) Diamondback (which approval may not be unreasonably withheld or conditioned) or (y) the affirmative vote of the holders of at least 80% of the voting power of the capital stock of Viper Inc. Initially, there will be two Diamondback designees to the board of directors of Viper Inc.—Travis Stice and Kaes Van’t Hof.

The Partnership has requested that, at the open of business on November 13, 2023, Nasdaq cease trading of the common units and commence trading of the Class A Common Stock on Nasdaq under the existing ticker symbol “VNOM.” No action by the current holders of common units is currently anticipated.A new CUSIP number has been issued for the Class A Common Stock, which will become effective at the Effective Time. Because the Partnership is already treated as a corporation for U.S. federal income tax purposes, we expect that the Conversion will not affect our status as a corporation for U.S. federal income tax purposes or materially impact the U.S. federal income tax treatment of our current public common unitholders.

2031 Notes Offering

On October 19, 2023, we completed the 2031 Notes Offering of $400.0 million in aggregate principal amount of our Senior Notes due November 1, 2031. We received net proceeds of approximately $394.4 million, after deducting the initial purchasers’ discount and expected transaction costs, from the 2031 Notes Offering.

See Note 13—Subsequent Events of the notes to the condensed consolidated financial statements for further detail.

Recent Acquisition

On November 1, 2023, we acquired certain mineral and royalty interests for approximately 9.02 million common units and $750 million in cash, subject to customary post-closing adjustments. The mineral and royalty interests acquired in the Acquisition represent approximately 4,600 net royalty acres in the Permian Basin, plus approximately 2,700 additional net royalty acres in other major basins. The cash portion of this transaction was funded through a combination of cash on hand and held in escrow, borrowings under the Operating Company’s revolving credit facility, the proceeds from the 2031 Notes Offering and $200.0 million of proceeds from the issuance of common units to Diamondback under the common unit purchase agreement.

See Note 13—Subsequent Events of the notes to the condensed consolidated financial statements for further detail.

After giving effect to the Acquisition, our footprint of mineral and royalty interests totaled approximately 34,500 net royalty acres, approximately 46% of which are operated by Diamondback.

Commodity Prices

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the future, 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 the nine months ended 2023 and 2022, ~~and 2021,~~the NYMEX WTI ~~has ranged from $47.62 to $123.70~~price averaged $77.28 and $98.25 per Bbl, respectively, and ~~the~~ NYMEX Henry Hub price ~~of natural gas has ranged from $2.45 to $9.68~~averaged $2.58 and $6.69 per MMBtu, ~~with seven-year highs reached in 2022.~~respectively. The war in Ukraine and the ~~COVID-19 pandemic,~~Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, ~~and recent~~ measures to combat persistent inflation and instability in the financial sector have ~~continued~~contributed to ~~contribute to~~recent economic and pricing volatility ~~during 2022.~~and may continue to impact pricing throughout 2023. Additionally, OPEC and its non-OPEC allies, known collectively as OPEC+, continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels, and has planned production decreases in order to stabilize oil prices during the fourth quarter. However, pricing may remain volatile during the remainder of 2022. We cannot reasonably predict whether production levels will remain at current levels or the impact the full extent of the events above may have on our industry and our business.

Although average oil prices decreased during the third quarter of 2022 from the second quarter of 2022, the commodity prices and industry conditions remained favorable and, based on the results of the quarterly ceiling test, we were not required to record an impairment on our proved oil and natural gas interests for the quarter ended September 30, 2022. If commodity prices deteriorate, 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 third quarter of 2022, we acquired, from unrelated third-party sellers, mineral and royalty interests representing 165 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $40.1 million, subject to post-closing adjustments. We divested 93 net royalty acres of third party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate sales price of $29.9 million, subject to closing adjustments. Our footprint of mineral and royalty interests totaled 26,789 net royalty acres at September 30, 2022.

~~Cash Distributions on Common Units~~

In July 2022, the board of directors of our General Partner approved a distribution policy, effective beginning with our distribution payable for the third quarter of 2022, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our unit buyback program. The board updated the distribution policy in November 2022, providing that lease bonus payments and other similar, one-time, non-recurring payments will be excluded from the calculation of the Partnership’s and the Operating Company’s available cash.levels.

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Production and Operational Update

~~Third party operated net wells turned to~~Continuing the trend of increasing production, ~~on our acreage~~average oil production per day during the third 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~~2023 was the highest in ~~the Partnership’s~~our history. ~~There~~As of November 1, 2023, there are ~~currently 49~~73 rigs operating on our mineral and royalty acreage, 11ten of which are operated by Diamondback. ~~Although demand for oil and natural gas and commodity prices~~As a result of the continued outperformance of our production goals, as well as the Acquisition, we have increased our fourth quarter 2023 oil production guidance by approximately 11% at midpoint compared to average daily oil production in the ~~current year, Diamondback and certain of our other operators have kept production on our acreage relatively flat during 2022 and expect to maintain relatively flat volumes in the fourth~~third quarter of ~~2022 and~~2023. We expect production to decline by approximately two to three percent in the first quarter of ~~2023. Our~~2024 on a pro forma basis, but to grow throughout the year with fourth quarter 2024 production and free cash flow 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. As a result of Diamondback’s consistent focus on developing our high concentration royalty acreage, primarily in the Northern Midland Basin, we expect our Diamondback-operated full year 2023 oil production to increase byending approximately ~~10% compared to 2022.~~five percent higher than pro forma fourth quarter 2023.

~~The following table summarizes~~After giving effect to the Acquisition, our gross well information as of ~~the dates indicated:~~November 1, 2023 is as follows:


		Diamondback Operated		Third Party Operated		Total			Diamondback Operated		Third Party Operated		Total
Horizontal wells turned to production (third quarter 2022)(1):
Horizontal wells turned to production(1):								Horizontal wells turned to production(1):
Gross wells	Gross wells	52		221		273		Gross wells	53		157		210
Net 100% royalty interest wells	Net 100% royalty interest wells	2.8		2.0		4.8		Net 100% royalty interest wells	4.4		1.6		6.0
Average percent net royalty interest	Average percent net royalty interest	5.4	%	0.9	%	1.7	%	Average percent net royalty interest	8.3	%	1.0	%	2.9	%

Horizontal producing well count (as of October 20, 2022):
Horizontal producing well count:								Horizontal producing well count:
Gross wells	Gross wells	1,504		4,838		6,342		Gross wells	1,782		9,293		11,075
Net 100% royalty interest wells	Net 100% royalty interest wells	113.6		63.7		177.3		Net 100% royalty interest wells	125.8		105.6		231.4
Average percent net royalty interest	Average percent net royalty interest	7.6	%	1.3	%	2.8	%	Average percent net royalty interest	7.1	%	1.1	%	2.1	%

Horizontal active development well count (as of October 20, 2022)(2):
Horizontal active development well count(2):								Horizontal active development well count(2):
Gross wells	Gross wells	95		475		570		Gross wells	123		743		866
Net 100% royalty interest wells	Net 100% royalty interest wells	5.5		5.1		10.6		Net 100% royalty interest wells	5.8		8.2		14.0
Average percent net royalty interest	Average percent net royalty interest	5.7	%	1.1	%	1.8	%	Average percent net royalty interest	4.7	%	1.1	%	1.6	%

Line of sight wells (as of October 20, 2022)(3):
Line of sight wells(3):								Line of sight wells(3):
Gross wells	Gross wells	166		354		520		Gross wells	143		540		683
Net 100% royalty interest wells	Net 100% royalty interest wells	8.3		3.6		11.9		Net 100% royalty interest wells	9.5		8.8		18.3
Average percent net royalty interest	Average percent net royalty interest	5.0	%	1.0	%	2.3	%	Average percent net royalty interest	6.6	%	1.6	%	2.7	%

(1) Average lateral length of ~~10,880.~~10,912.

(2) The total ~~570~~866 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 ~~520~~683 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 September 30, ~~2022~~2023 and June 30, ~~2022~~

~~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. 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.2023

Results of Operations

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


		Three Months Ended					Three Months Ended
		September 30, 2022		June 30, 2022					September 30, 2023		June 30, 2023
		(In thousands)				(In thousands)

Operating income:	Operating income:							Operating income:
Oil income	Oil income	$	167,934	$	191,195			Oil income	$	168,008	$	139,300
Natural gas income	Natural gas income	28,638		23,793				Natural gas income	8,893		5,090
Natural gas liquids income	Natural gas liquids income	23,337		23,842				Natural gas liquids income	18,713		13,807
Royalty income	Royalty income	219,909		238,830				Royalty income	195,614		158,197
Lease bonus income—related party								Lease bonus income—related party	97,237		1,277
Lease bonus income	Lease bonus income	1,497		329				Lease bonus income	196		1,134

Other operating income	Other operating income	211		163				Other operating income	193		179
Total operating income	Total operating income	221,617		239,322				Total operating income	293,240		160,787
Costs and expenses:	Costs and expenses:							Costs and expenses:
Production and ad valorem taxes	Production and ad valorem taxes	15,638		16,039				Production and ad valorem taxes	12,286		12,621

Depletion	Depletion	30,460		31,962				Depletion	36,280		34,064

General and administrative expenses	General and administrative expenses	2,139		1,880				General and administrative expenses	1,880		2,008

Total costs and expenses	Total costs and expenses	48,237		49,881				Total costs and expenses	50,446		48,693
Income (loss) from operations	Income (loss) from operations	173,380		189,441				Income (loss) from operations	242,794		112,094
Other income (expense):	Other income (expense):							Other income (expense):
Interest expense, net	Interest expense, net	(10,731)		(9,782)				Interest expense, net	(11,203)		(11,291)

Gain (loss) on derivative instruments, net	Gain (loss) on derivative instruments, net	882		(1,889)				Gain (loss) on derivative instruments, net	(2,988)		(12,594)

Other income, net	Other income, net	162		32				Other income, net	489		172
Total other expense, net	Total other expense, net	(9,687)		(11,639)				Total other expense, net	(13,702)		(23,713)
Income (loss) before income taxes	Income (loss) before income taxes	163,693		177,802				Income (loss) before income taxes	229,092		88,381
Provision for (benefit from) income taxes	Provision for (benefit from) income taxes	(46,409)		6,182				Provision for (benefit from) income taxes	21,879		8,450
Net income (loss)	Net income (loss)	210,102		171,620				Net income (loss)	207,213		79,931
Net income (loss) attributable to non-controlling interest	Net income (loss) attributable to non-controlling interest	130,762		137,598				Net income (loss) attributable to non-controlling interest	128,614		49,381
Net income (loss) attributable to Viper Energy Partners LP	Net income (loss) attributable to Viper Energy Partners LP	$	79,340	$	34,022			Net income (loss) attributable to Viper Energy Partners LP	$	78,599	$	30,550

2022

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


		Three Months Ended				Three Months Ended
		September 30, 2022		June 30, 2022				September 30, 2023		June 30, 2023
Production data:	Production data:						Production data:
Oil (MBbls)	Oil (MBbls)	1,828		1,798			Oil (MBbls)	2,037		1,924
Natural gas (MMcf)	Natural gas (MMcf)	4,086		3,898			Natural gas (MMcf)	4,900		4,685
Natural gas liquids (MBbls)	Natural gas liquids (MBbls)	664		607			Natural gas liquids (MBbls)	867		724
Combined volumes (MBOE)(1)	Combined volumes (MBOE)(1)	3,173		3,054			Combined volumes (MBOE)(1)	3,721		3,429

Average daily oil volumes (BO/d)	Average daily oil volumes (BO/d)	19,870		19,758			Average daily oil volumes (BO/d)	22,141		21,143
Average daily combined volumes (BOE/d)	Average daily combined volumes (BOE/d)	34,489		33,560			Average daily combined volumes (BOE/d)	40,446		37,681

Average sales prices:	Average sales prices:						Average sales prices:
Oil ($/Bbl)	Oil ($/Bbl)	$	91.87	$	106.34		Oil ($/Bbl)	$	82.48	$	72.40
Natural gas ($/Mcf)	Natural gas ($/Mcf)	$	7.01	$	6.10		Natural gas ($/Mcf)	$	1.81	$	1.09
Natural gas liquids ($/Bbl)	Natural gas liquids ($/Bbl)	$	35.15	$	39.28		Natural gas liquids ($/Bbl)	$	21.58	$	19.07
Combined ($/BOE)(2)	Combined ($/BOE)(2)	$	69.31	$	78.20		Combined ($/BOE)(2)	$	52.57	$	46.14

Oil, hedged ($/Bbl)(3)	Oil, hedged ($/Bbl)(3)	$	91.26	$	105.59		Oil, hedged ($/Bbl)(3)	$	81.44	$	71.39
Natural gas, hedged ($/Mcf)(3)	Natural gas, hedged ($/Mcf)(3)	$	5.36	$	4.72		Natural gas, hedged ($/Mcf)(3)	$	1.47	$	0.65
Natural gas liquids ($/Bbl)(3)	Natural gas liquids ($/Bbl)(3)	$	35.15	$	39.28		Natural gas liquids ($/Bbl)(3)	$	21.58	$	19.07
Combined price, hedged ($/BOE)(3)	Combined price, hedged ($/BOE)(3)	$	66.82	$	75.99		Combined price, hedged ($/BOE)(3)	$	51.55	$	44.97

Average costs ($/BOE):	Average costs ($/BOE):						Average costs ($/BOE):
Production and ad valorem taxes	Production and ad valorem taxes	$	4.93	$	5.25		Production and ad valorem taxes	$	3.30	$	3.68

General and administrative - cash component(4)	General and administrative - cash component(4)	0.56		0.51			General and administrative - cash component(4)	0.41		0.51
Total operating expense - cash	Total operating expense - cash	$	5.49	$	5.76		Total operating expense - cash	$	3.71	$	4.19

General and administrative - non-cash unit compensation expense	General and administrative - non-cash unit compensation expense	$	0.11	$	0.11		General and administrative - non-cash unit compensation expense	$	0.10	$	0.08
Interest expense, net	Interest expense, net	$	3.38	$	3.20		Interest expense, net	$	3.01	$	3.29
Depletion	Depletion	$	9.60	$	10.47		Depletion	$	9.75	$	9.93

(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 $37.4 million during the third quarter of 2023 compared to the second quarter of 2023. Changes in average pricing contributed to approximately $26.3 million of the total increase, primarily due to higher average prices for oil, and to a lesser extent, natural gas and natural gas liquids received for our production in the third quarter of 2023. The remaining increase of $11.1 million in royalty income is due to a 9% increase in production in the third quarter of 2023 compared to the second quarter of 2023, which resulted primarily from new well development in areas where Viper has a higher royalty interest.

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Lease Bonus Income-Related Party

Lease bonus income from Diamondback increased $96.0 million due to one new lease of $95.8 million covering approximately 12,778 net mineral acres in Midland County, Texas, and another covering approximately 140 net mineral acres in Pecos County, Texas, in the third quarter of 2023, compared to receiving payment for two new leases and two lease extensions covering approximately 165 net mineral acres in Martin and Wheeler Counties; Texas, in the second quarter of 2023.

See Note 2—Summary of Significant Accounting Policies of the notes to the condensed consolidated financial statements for further detail.

Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the periods indicated:


	Three Months Ended
	September 30, 2023						June 30, 2023
	Amount (In thousands)		Per BOE		Percentage of Royalty Income		Amount (In thousands)		Per BOE		Percentage of Royalty Income
Production taxes	$	9,892	$	2.66	5.1	%	$	7,807	$	2.28	5.0	%
Ad valorem taxes	2,394		0.64		1.2		4,814		1.40		3.0
Total production and ad valorem taxes	$	12,286	$	3.30	6.3	%	$	12,621	$	3.68	8.0	%

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 third quarter of 2023 were consistent with the second quarter of 2023. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. In the third quarter of 2023, we lowered our full year estimate of ad valorem taxes based on expected reductions in our tax rates and accordingly, decreased our ad valorem accrual compared to the second quarter of 2023.

Depletion

The $2.2 million increase in depletion expense for the third quarter of 2023 compared to the second quarter of 2023 was due primarily to production growth between the periods. The average depletion rate decreased slightly to $9.75 per BOE for the third quarter of 2023 compared to $9.93 per BOE for the second quarter of 2023.

Derivative Instruments

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


	Three Months Ended
	September 30, 2023		June 30, 2023
	(In thousands)
Gain (loss) on derivative instruments	$	(2,988)	$	(12,594)
Net cash receipts (payments) on derivatives	$	(3,807)	$	(3,997)

We recorded losses on our derivative instruments for the three months ended September 30, 2023 and June 30, 2023. The decrease in the loss was primarily due to recording a gain of $2.0 million on natural gas basis swaps in the third quarter of 2023 compared to a loss of $7.6 million in the second quarter of 2023. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. See Note 10—Derivatives of the notes to the condensed consolidated financial statements for additional discussion of our open contracts at September 30, 2023.

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Provision for (Benefit from) Income Taxes

The $13.4 million increase in income tax expense for the third quarter of 2023 compared to the second quarter of 2023 is primarily due to the increase in pre-tax income attributable to us, resulting largely from the increases in royalty income and lease bonus income discussed above. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements for further details.

Comparison of the Nine Months Ended September 30, 2023 and 2022

Results of Operations

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


	Nine Months Ended September 30,
	2023		2022


Operating income:
Oil income	$	443,927	$	514,180
Natural gas income	22,974		67,621
Natural gas liquids income	47,995		70,027
Royalty income	514,896		651,828
Lease bonus income—related party	105,585		6,652
Lease bonus income	1,730		3,856

Other operating income	774		506
Total operating income	622,985		662,842
Costs and expenses:
Production and ad valorem taxes	37,794		45,547

Depletion	101,331		89,833


General and administrative expenses	6,652		5,972

Total costs and expenses	145,777		141,352
Income (loss) from operations	477,208		521,490
Other income (expense):
Interest expense, net	(32,180)		(30,158)


Gain (loss) on derivative instruments, net	(30,685)		(19,366)

Other income, net	802		200
Total other expense, net	(62,063)		(49,324)
Income (loss) before income taxes	415,145		472,166
Provision for (benefit from) income taxes	39,735		(37,597)
Net income (loss)	375,410		509,763
Net income (loss) attributable to non-controlling interest	232,294		379,796
Net income (loss) attributable to Viper Energy Partners LP	$	143,116	$	129,967

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


	Nine Months Ended September 30,
	2023		2022
Production data:
Oil (MBbls)	5,771		5,259
Natural gas (MMcf)	13,809		11,713
Natural gas liquids (MBbls)	2,224		1,857
Combined volumes (MBOE)(1)	10,297		9,068

Average daily oil volumes (BO/d)	21,139		19,264
Average daily combined volumes (BOE/d)	37,718		33,216


Average sales prices:
Oil ($/Bbl)	$	76.92	$	97.77
Natural gas ($/Mcf)	$	1.66	$	5.77
Natural gas liquids ($/Bbl)	$	21.58	$	37.71
Combined ($/BOE)(2)	$	50.00	$	71.88

Oil, hedged ($/Bbl)(3)	$	75.85	$	96.40
Natural gas, hedged ($/Mcf)(3)	$	1.39	$	4.62
Natural gas liquids ($/Bbl)(3)	$	21.58	$	37.71
Combined price, hedged ($/BOE)(3)	$	49.03	$	69.60

Average costs ($/BOE):
Production and ad valorem taxes	$	3.67	$	5.02
General and administrative - cash component(4)	0.55		0.55
Total operating expense - cash	$	4.22	$	5.57

General and administrative - non-cash unit compensation expense	$	0.10	$	0.11
Interest expense, net	$	3.13	$	3.33
Depletion	$	9.84	$	9.91

(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 decreased ~~$18.9~~$136.9 million during the ~~third quarter of 2022,~~nine months ended September 30, 2023 compared to the ~~second quarter of~~same period in 2022. Changes in average pricing during 2023 contributed to approximately ~~$25.5~~$212.9 million of the total decrease due primarily to lower average oil, prices and to a lesser extent, natural gas liquids prices, offset slightly by higher average natural gas prices during the third quarter of 2022. The impact of lower pricing was partially offset by an increase of $6.6 million due to a 4% growth in production in the third quarter of 2022 compared to the second quarter of 2022. This production growth resulted from new wells additions between periods and having one additional day of production in the third quarter of 2022.

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~~Production and Ad Valorem Taxes~~

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

Three Months Ended
September 30, 2022 June 30, 2022
Amount
(In thousands) Per BOE Percentage of Royalty Income Amount
(In thousands) Per BOE Percentage of Royalty Income
Production taxes $ 11,591 $ 3.65 5.3 % $ 12,023 $ 3.94 5.0 %
Ad valorem taxes 4,047 1.28 1.8 4,016 1.31 1.7
Total production and ad valorem taxes $ 15,638 $ 4.93 7.1 % $ 16,039 $ 5.25 6.7 %

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 third quarter of 2022 were consistent with the second quarter of 2022. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes were also consistent between periods.

~~Depletion~~

The $1.5 million, or 5%, decrease in depletion expense for the third quarter of 2022 compared to the second quarter of 2022 was due primarily to a reduction in the average depletion rate to $9.60 for the three months ended September 30, 2022 compared to $10.47 for three months ended June 30, 2022. The rate decrease was primarily due to higher SEC oil and natural gas prices utilized in the reserve calculations in the third quarter of 2022, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells, as well as changes in cost to be excluded from depletion. The reduction in the average depletion rate was primarily offset by higher production in the third quarter of 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
September 30, 2022 June 30, 2022
(In thousands)
Gain (loss) on derivative instruments $ 882 $ (1,889)
Net cash receipts (payments) on derivatives(1)
$ (10,263) $ (6,765)

~~(1)The three months ended September 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $2.4 million.~~

We recorded a gain on our derivative instruments for the third quarter of 2022, compared to a loss for the second quarter of 2022. This change is primarily due to market prices decreasing and in some cases being lower than the strike prices on our open oil and natural gas derivative contracts at September 30, 2022 compared to June 30, 2022. This gain was largely offset by net cash payments made to settle matured contracts and for the early termination of certain commodity contracts in the third quarter of 2022. 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 September 30, 2022.~~

~~Provision for (Benefit from) Income Taxes~~

The $52.6 million decrease in income tax expense for the third quarter of 2022 compared to the second quarter of 2022 is primarily due to recognition of discrete income tax benefit as a result of the partial reduction of the valuation allowance against our deferred tax assets and to lower pre-tax net income driven primarily by a decrease in royalty income. See Note 9—~~Income Taxes~~ ~~of the notes to the condensed consolidated financial statements included elsewhere in this report for further details.~~

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~~Comparison of the Nine Months Ended September 30, 2022 and 2021~~

~~Results of Operations~~

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

Nine Months Ended September 30,
2022 2021
(In thousands)
Operating income:
Oil income $ 514,180 $ 272,450
Natural gas income 67,621 30,651
Natural gas liquids income 70,027 34,518
Royalty income 651,828 337,619
Lease bonus income 10,508 1,032
Other operating income 506 479
Total operating income 662,842 339,130
Costs and expenses:
Production and ad valorem taxes 45,547 23,426
Depletion 89,833 74,230
General and administrative expenses 5,972 6,118
Total costs and expenses 141,352 103,774
Income (loss) from operations 521,490 235,356
Other income (expense):
Interest expense, net (30,158) (24,161)
Gain (loss) on derivative instruments, net (19,366) (70,649)
Other income, net 200 77
Total other expense, net (49,324) (94,733)
Income (loss) before income taxes 472,166 140,623
Provision for (benefit from) income taxes (37,597) 941
Net income (loss) 509,763 139,682
Net income (loss) attributable to non-controlling interest 379,796 121,208
Net income (loss) attributable to Viper Energy Partners LP $ 129,967 $ 18,474

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

Nine Months Ended September 30,
2022 2021
Production data:
Oil (MBbls) 5,259 4,378
Natural gas (MMcf) 11,713 9,828
Natural gas liquids (MBbls) 1,857 1,359
Combined volumes (MBOE)(1)
9,068 7,375
Average daily oil volumes (BO/d) 19,264 16,037
Average daily combined volumes (BOE/d) 33,216 27,015
Average sales prices:
Oil ($/Bbl) $ 97.77 $ 62.23
Natural gas ($/Mcf) $ 5.77 $ 3.12
Natural gas liquids ($/Bbl) $ 37.71 $ 25.40
Combined ($/BOE)(2)
$ 71.88 $ 45.78
Oil, hedged ($/Bbl)(3)
$ 96.40 $ 48.26
Natural gas, hedged ($/Mcf)(3)
$ 4.62 $ 3.12
Natural gas liquids ($/Bbl)(3)
$ 37.71 $ 25.40
Combined price, hedged ($/BOE)(3)
$ 69.60 $ 37.48
Average costs ($/BOE):
Production and ad valorem taxes $ 5.02 $ 3.18
General and administrative - cash component(4)
0.55 0.70
Total operating expense - cash $ 5.57 $ 3.88
General and administrative - non-cash unit compensation expense $ 0.11 $ 0.13
Interest expense, net $ 3.33 $ 3.28
Depletion $ 9.91 $ 10.07

~~(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.~~

~~(2)Realized price net of all deducts for gathering, transportation and processing.~~

~~(3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices.~~

~~(4)Excludes non-cash unit-based compensation expense for the respective periods presented.~~

~~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 $314.2 million during the nine months ended September 30, 2022 compared to the same period in 2021. As discussed in “—Recent Developments~~,” ~~strong oil prices in 2022 and to a lesser extent, the continuing recovery in~~ natural gas and natural gas liquids prices ~~contributed~~received for our production in 2023. The decrease due to ~~approximately $240.9~~lower pricing was partially offset by $76.0 million ~~of the total increase.~~

~~The remaining $73.3 million of the total increase~~ in additional royalty income ~~is attributable~~due to ~~the 23%~~a 14% increase in production volumes during the nine months ended September 30, ~~2022~~2023 compared to the same period in ~~2021.~~2022. This production growth stems from new well ~~additions~~development in areas where Viper has a higher royalty interest between ~~periods primarily due to the Swallowtail Acquisition.~~periods.

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Lease Bonus ~~Income~~Income-Related Party

Lease bonus income from Diamondback increased ~~during~~$98.9 million due to five new leases in Martin, Midland, Pecos and Wheeler Counties; Texas, and two lease extensions in Martin County, Texas, including one lease of $95.8 million for the nine months ended September 30, ~~2022~~2023, compared to receiving payment for four leases in Martin County, Texas, during the same period in ~~2021 due primarily~~2022.

See Note 2—Summary of Significant Accounting Policies of the notes to ~~leasing certain assets we acquired in~~ the ~~Swallowtail Acquisition to Diamondback in the first quarter of 2022.~~condensed consolidated financial statements for further details.

Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the nine months ended September 30, ~~2022~~2023 and ~~2021~~2022:


		Nine Months Ended September 30,													Nine Months Ended September 30,
		2022						2021							2023						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	$	33,484	$	3.69	5.1	%	$	17,264	$	2.34	5.1	%	Production taxes	$	25,876	$	2.51	5.0	%	$	33,484	$	3.69	5.1	%
Ad valorem taxes	Ad valorem taxes	12,063		1.33		1.9		6,162		0.84		1.8		Ad valorem taxes	11,918		1.16		2.3		12,063		1.33		1.9
Total production and ad valorem taxes	Total production and ad valorem taxes	$	45,547	$	5.02	7.0	%	$	23,426	$	3.18	6.9	%	Total production and ad valorem taxes	$	37,794	$	3.67	7.3	%	$	45,547	$	5.02	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 nine months ended September 30, ~~2022~~2023 remained consistent with the same period in ~~2021.~~2022. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. The slight increase in ad valorem taxes as a percentage of royalty income 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 average commodity ~~prices. Ad~~prices in 2022.

After giving effect to the Acquisition, we expect our production and ad valorem ~~taxes remained consistent~~tax as a percentage of royalty income ~~for the nine months ended September 30, 2022 compared~~ to ~~the same period~~be 7% in ~~2021.~~2023.

Depletion

The ~~$15.6~~$11.5 million ~~or 21%,~~ increase in depletion expense for the nine months ended September 30, ~~2022~~2023 compared to the same period in ~~2021~~2022 was due primarily to production growth between the ~~periods.~~periods resulting largely from new well development. The average depletion rate ~~decreased to $9.91~~remained relatively flat at $9.84 per BOE for the nine months ended September 30, ~~2022~~2023 compared to ~~the rate of $10.07~~ $9.91 per BOEfor the same period in ~~2021. The rate decrease largely resulted~~2022.

After giving effect to the Acquisition, we expect depletion expense to range from ~~higher SEC oil and natural gas prices utilized~~approximately $150.0 million to $161.5 million in ~~the reserve calculations in 2022, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.~~2023.

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:


		Nine Months Ended September 30,					Nine Months Ended September 30,
		2022		2021			2023		2022
		(In thousands)					(In thousands)
Gain (loss) on derivative instruments	Gain (loss) on derivative instruments	$	(19,366)	$	(70,649)	Gain (loss) on derivative instruments	$	(30,685)	$	(19,366)
Net cash receipts (payments) on derivatives(1)	Net cash receipts (payments) on derivatives(1)	$	(27,292)	$	(61,188)	Net cash receipts (payments) on derivatives(1)	$	(10,019)	$	(27,292)

(1)The nine months ended September 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $6.6 million.

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We recorded losses on our derivative instruments for the nine months ended September 30, ~~2022~~2023 and ~~2021~~2022 primarily due to market prices being higher than the strike prices on our open 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~~See Note 10—Derivatives of the notes to ~~fair value and recognize~~ the ~~cash and non-cash changes in fair value on derivative instruments in our~~ condensed consolidated financial statements for additional discussion of ~~operations under the line item captioned “Gain (loss) on derivative instruments, net.”~~

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~~Interest Expense, Net~~

~~The $6.0 million increase in net interest expense for the nine months ended~~our open contracts at September 30, ~~2022 compared to the same period in 2021 was due primarily to an increase in average outstanding borrowings and interest rates on the Operating Company’s revolving credit facility.~~2023.

Provision for (Benefit from) Income Taxes

~~Income~~The $77.3 million increase in income tax ~~benefit~~expense for the nine months ended September 30, 2023 compared to the same period in 2022 ~~of $37.6 million~~ resulted primarily from ~~recognition~~the increase in pre-tax income attributable to us as a result of the expiration of the special income allocation at December 31, 2022, and from the impact of discrete income tax benefit asrecognized in the third quarter of 2022 related to a ~~result of the partial reduction~~change in the valuation allowance against our deferred tax assets. This was partially offset by an increase in current tax expense due to the increase in pre-tax income, which was driven largely by increases in royalty income and lease bonus income as well as changes in the gain or loss recognized 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.

After giving effect to the Acquisition, we expect our cash tax rate to be approximately 21% of pre-tax income for the year ended December 31, 2023.

Net Income (Loss) Attributable to Non-controlling Interest

The $147.5 million decrease in net income (loss) attributable to non-controlling interest for the nine months ended September 30, 2023 compared to the same period in 2022 is primarily due to the expiration of the special income allocation at December 31, 2022.

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 revolving credit ~~agreement.~~facility. Our primary uses of cash have been distributions to our unitholders, repayments 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. At September 30, ~~2022,~~2023, we had approximately ~~$266.6~~$746.8 million of liquidity consisting of ~~$11.6~~$146.8 million in cash and cash equivalents and ~~$255.0~~$600.0 million available under the Operating Company’s revolving credit ~~agreement~~facility. See further discussion of changes in our sources of cash in “—Capital Resources” below.

Our working capital requirements are supported by our cash and cash equivalents and the Operating Company’s revolving credit ~~agreement.~~facility. We may draw on the Operating Company’s revolving credit ~~agreement~~facility 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~~ war in Ukraine and the Israel-Hamas war, the depressed commodity markets ~~and,~~ and/or adverse macroeconomic conditions, including persistent inflation, rising interests rates, global supply chain disruptions and increasing concerns over a potential economic downturn or 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.

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Cash Flows

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


		Nine Months Ended September 30,					Nine Months Ended September 30,
		2022		2021			2023		2022
		(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	$	513,241	$	199,672	Net cash provided by (used in) operating activities	$	492,397	$	513,241
Net cash provided by (used in) investing activities	Net cash provided by (used in) investing activities	19,611		(6,728)		Net cash provided by (used in) investing activities	(176,749)		19,611
Net cash provided by (used in) financing activities	Net cash provided by (used in) financing activities	(560,684)		(140,525)		Net cash provided by (used in) financing activities	(187,013)		(560,684)
Net increase (decrease) in cash and cash equivalents	Net increase (decrease) in cash and cash equivalents	$	(27,832)	$	52,419	Net increase (decrease) in cash and cash equivalents	$	128,635	$	(27,832)

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. The ~~increase~~decrease in net cash provided by operating activities during the nine months ended September 30, ~~2022~~2023 compared to the same period in ~~2021~~2022 was primarily driven by ~~(i) higher~~lower royalty ~~income, (ii)~~income. This was partially offset by an increase in cash flows from related party 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 royalty income payments from our operators (ii) an increase in production and ad valorem expenses due to the corresponding increase in royalty income and (iii) an increase in cash paid for taxes, as our tax provision reflects an increase in current cash income taxes. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

Net cash used in investing activities during the nine months ended September 30, 2023 primarily related to acquisitions of oil and natural gas interests from third parties, which includes a $50.0 million escrow deposit made for the Acquisition, and the acquisition of oil and natural gas interests in the Drop Down.

Net cash provided by investing activities during the nine months ended September 30, 2022 primarily related to proceeds from the ~~divestitures~~divestiture of oil and natural gas interests, partially offset by expenditures for acquisitions of oil and natural gas interests.

Financing Activities

Net cash used in ~~investing~~financing activities during the nine months ended September 30, ~~2021~~2023 primarily ~~related~~resulted from distributions of $212.1 million and $67.2 million of common unit repurchases as we continue to ~~acquisitions~~return capital to our unitholders. These cash outflows were partially offset by net borrowings of ~~oil and natural gas interests.~~$98.0 million under the Operating Company’s revolving credit facility.

~~Financing Activities~~

~~Consistent with our strategy to return cash flow to unitholders, net~~Net cash used in financing activities during the nine months ended September 30, 2022, was primarily related to distributions of $333.7 million to our unitholders and $118.9 million of common unit repurchases which included approximately $37.3 million for the repurchase of 1.5 million common units from a significant unitholder in a privately negotiated transaction. Additionally, we paid ~~approximately~~ $49.0 million for the repurchase of principal outstanding on the Notes ~~as discussed in~~ “—~~2022 Debt Transactions~~” ~~below~~ and made net repayments of $59.0 million ~~of borrowings~~ under the Operating Company’s revolving credit ~~facility using cash on hand.~~

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

Capital Resources

The Operating Company’s Revolving Credit Facility

At On September ~~30, 2022,~~22, 2023, the Operating Company entered into an eleventh and separately a twelfth amendment to the existing credit agreement, which among other things, (i) extended the maturity date from June 2, 2025, to September 22, 2028, (ii) maintained the maximum credit amount of $2.0 billion, (iii) increased the borrowing base from $1.0 billion to $1.3 billion upon consummation of the Acquisition, (iv) increased the aggregate elected commitment amount from $750.0 million to $850.0 million, and (v) waived the automatic reduction of the borrowing base that would otherwise occur upon the consummation of the 2031 Notes. The Operating Company had ~~elected a commitment amount~~$250.0 million in outstanding borrowings and $600.0 million of ~~$500.0 million~~availability on its revolving credit ~~agreement with $245.0 million of outstanding borrowings.~~facility at September 30, 2023.

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~~2022 Debt Transactions~~Issuance of 2031 Notes

~~During~~On October 19, 2023, we completed the ~~nine months ended September 30, 2022, the Operating Company used a combination~~2031 Notes Offering of ~~cash on hand and borrowings under the Operating Company’s credit agreement to repurchase a portion of the 5.375% 2027 Senior Notes~~$400.0 million in ~~the~~ aggregate principal amount of ~~$49.6~~its 7.375% Senior Notes maturing on November 1, 2031. Through maturity, we expect to incur approximately $236.0 million in aggregate interest costs ($29.5 million annually) for ~~total cash consideration of $49.0 million.~~the 2031 Notes.

~~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 and Note 13—Subsequent Events of the notes to the condensed consolidated financial statements ~~included elsewhere in this report~~ for additional discussion of our outstanding debt ~~at September 30, 2022.~~and discussion of the Acquisition and the 2031 Notes Offering, respectively.

Capital Requirements

Acquisition Funding

The $750.0 million cash portion of the purchase price for the Acquisition completed on November 1, 2023, was funded through a combination of cash on hand and cash held in escrow, borrowings under the Operating Company’s revolving credit facility, proceeds from the 2031 Notes Offering and proceeds from our issuance of common units to Diamondback. See Note 13—Subsequent Events of the notes to the condensed consolidated financial statements for further discussion.

Repurchases of Securities

~~On July 26, 2022,~~Under our current common unit repurchase program, the board of directors of our General Partner ~~increased the authorization~~has authorized us to acquire up to $750.0 million of our common ~~unit repurchase program from $250.0 million to $750.0 million.~~units, excluding excise tax. As of September 30, ~~2022, $561.0~~2023, $462.9 million remains available for use to repurchase units under ~~the~~this repurchase ~~program.~~program, excluding excise tax.

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 Operating Company will pay a cash distribution for the third quarter of ~~2022 is $0.49~~2023 in accordance with its distribution policy of $0.70 per ~~common~~Operating Company unit ~~payable~~ on November ~~25, 2022~~24, 2023 to ~~common~~eligible unitholders of record at the close of business on November ~~17, 2022.~~16, 2023.

We will pay a cash distribution for the third quarter of 2023 in accordance with its distribution policy of $0.57 per common unit on November 24, 2023 to eligible our unitholders of record at the close of business on November 16, 2023. The ~~dividend~~distribution to common unitholders consists of a base quarterly dividend of ~~$0.25~~$0.27 per common unit and a variable quarterly ~~dividend~~distribution of ~~$0.24~~$0.30 per common unit.

Future base and variable dividends are at the discretion of the board of directors of our General Partner.

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 the repurchase program and distributions.

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.~~2022.

Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies included in the ~~condensed~~ notes to the condensed consolidated financial statements ~~included elsewhere in this Quarterly Report~~ for recent accounting pronouncements not yet adopted, if any.

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.

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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 war in Ukraine and the Israel-Hamas war, rising interest rates, global supply chain disruptions, a potential economic downturn or recession ~~the COVID-19 pandemic~~ and actions taken by OPEC members and other exporting

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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 as discussed in Note ~~10 —~~ 10—Derivatives of the notes to the condensed consolidated financial ~~statements included elsewhere in this report.~~statements.

At September 30, ~~2022~~2023, we had a net ~~asset~~liability derivative position related to our commodity price derivatives of ~~$4.5~~$10.9 million. Utilizing actual derivative contractual volumes under our contracts as of September 30, ~~2022,~~2023, a 10% increase in forward curves associated with the underlying commodity would have increased the net ~~asset~~liability position by ~~$0.6~~$4.1 million to ~~$5.1~~approximately $15.0 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net ~~asset~~liability derivative position by ~~$0.3~~$3.7 million to ~~$4.2~~approximately $7.2 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Credit Risk

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

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under the Operating Company’s revolving credit ~~agreement.~~facility. The terms of the credit agreement provide for interest on borrowings at a floating rate equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”), or (ii) an ~~alternative~~alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and ~~3-month LIBOR~~1-month Adjusted Term SOFR plus ~~1.0%~~1.00%) ~~or LIBOR,~~, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternative base rate and from 2.00% to 3.00% per annum in the case of ~~LIBOR,~~Adjusted Term SOFR, in each case depending on the amount of the ~~loan~~loans outstanding in relation to the commitment, which is calculated using the least of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. 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.~~commitment. As of September 30, ~~2022,~~2023, we had ~~$245.0~~$250.0 million in outstanding borrowings. During the three and nine months ended September 30, ~~2022,~~2023, the weighted average interest rate on the Operating Company’s revolving credit facility was ~~4.75%~~7.58% and ~~3.53%, respectively.~~7.37%.

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.

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As of September 30, ~~2022,~~2023, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner have concluded that as of September 30, ~~2022,~~2023, 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 September 30, ~~2022~~2023 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. of the notes to the condensed consolidated financial statements.

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.

As of the date of this filing, we continue to be subject to 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,~~2022, 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,~~ ~~Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q~~ ~~for the quarterly period ended June 30, 2022, filed with the SEC on August 3, 2022,~~23, 2023 and in subsequent filings we make with the SEC. There have been no material changes in our risk factors from those described in ~~such reports.~~our Annual Report on Form 10-K for the year ended December 31, 2022.

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

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common unit repurchase activity for the three months ended September 30, ~~2022~~2023 was as follows:

Period
Total Number of Units Purchased(1)
Average Price Paid Per Unit(2)
Total Number of Units Purchased as Part of Publicly Announced Plan
Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(3)
(In thousands, except unit amounts)
July 1, 2022 - July 31, 2022 760,000 $ 26.51 760,000 $ 591,618
August 1, 2022 - August 31, 2022 529,972 $ 29.37 529,972 $ 576,050
September 1, 2022 - September 30, 2022 527,745 $ 28.44 527,745 $ 561,043
Total 1,817,717 $ 27.91 1,817,717


Period	Total Number of Units Purchased	Average Price Paid Per Unit(1)(3)		Total Number of Units Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(2)(3)
	(In thousands, except unit amounts)
July 1, 2023 - July 31, 2023	334,600	$	25.99	334,600	$	463,724
August 1, 2023 - August 31, 2023	30,000	$	28.76	30,000	$	462,861
September 1, 2023 - September 30, 2023	—	$	—	—	$	462,861
Total	364,600	$	26.22	364,600

(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)~~(2)On July 26, 2022, the board of directors of our General Partner increased the authorization ofunder our then-in-effect common unit repurchase program from $250.0 million to $750.0 ~~million.~~million, excluding excise tax. This repurchase program has no expiration date and 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.

(3)The Inflation Reduction Act of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022. All dollar amounts presented exclude such excise taxes, as applicable.

ITEM 5. OTHER INFORMATION

None of the directors or officers of our General Partner adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during our fiscal quarter ended September 30, 2023.

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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).
2.2						P urchase and Sale Agreement, dated as of September 4, 2023, by and among Royalty Asset Holdings, L P, Royalty Asset Holdings II, LP and Sa xum Asset Holdings, LP (collectively, as sell ers), Viper Energy Partners LLC (as buyer) and Viper Energy Partners LP (as parent, a nd collectively with Viper Energy Partners LLC , as buyer parties).
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.~~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 Amendment to Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of November 2, 2023. (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on November 2, 2023).
3.5						Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of May 9, ~~2018.~~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~~3.6						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~~3.7						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 Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on December 28, 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~~November 1, ~~2021,~~2023, by and among Viper Energy Partners LP, ~~Swallowtail Royalties LLC~~Warwick Royalty and ~~Swallowtail Royalties~~Mineral Master Fund LP, Royalty Asset Holdings, LP, Royalty Asset Holdings II, ~~LLC~~LP and Saxum Asset Holdings, LP (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on November 7, 2023.
4.3						Indenture, dated as of October 19, 2023, among Viper Energy Partners LP, as issuer, Viper Energy Partners LLC, as guarantor and Computershare Trust Company National Association, as trustee (including the form of Viper Energy Partners LP’s 7.375% Senior Notes due 2031) (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on October 25, 2023).
10.1						C ommon Unit Purchase and Sale Agreement, entered into on September 4, 2023, by and among Viper Energy Partners LP and Diamondback Energy, Inc . (incorporated by reference to Exhibit 10.1 of the Partnership ’s Current Report o n Form 8-K (File No. 001-36505) filed on September 7, ~~2021)~~2023).
10.2						E leventh Amendment to Amended and Restated Senior Secured Revolving Credi t Agreement dated as of September 22, 2 023, by an d among Viper Energy Partners LLC, as borrower , Viper Energy Partners LP, as par ent guarantor, Wells Fargo Ba nk, National Associat ion , as administrative age nt, and the lenders part y thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on September 28 , 2023).
10.3						Twelfth Am endment to Amended and Restated Senior Secured Revolving Credit Agreement dated as of September 22 , 2023, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Associat ion, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on September 28 , 2023).
10.4						Subordinated Promissory Note, dated as of October 19, 2023, made by Viper Energy Partners LLC payable to Viper Energy Partners LP (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on October 25, 2023).

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Exhibit Number						Description
10.5						Services and Secondment Agreement, dated as of November 2, 2023, by and among Diamondback E&P LLC, Viper Energy Partners LP, Viper Energy Partners GP LLC and Viper Energy Partners LLC (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on November 2, 2023).
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 September 30, ~~2022,~~2023, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement of Changes in Unitholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Condensed Notes to Consolidated Financial Statements.






104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).


*			Filed herewith.
**			The certifications attached as Exhibit 32.1 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

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


		VIPER ENERGY PARTNERS LP

		By:	VIPER ENERGY PARTNERS GP LLC
			its General Partner

Date:	November 8, ~~2022~~2023	By:	/s/ Travis D. Stice
			Travis D. Stice
			Chief Executive Officer

Date:	November 8, ~~2022~~2023	By:	/s/ Teresa L. Dick
			Teresa L. Dick
			Chief Financial Officer

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Period	Total Number of Units Purchased(1)	Average Price Paid Per Unit(2)		Total Number of Units Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(3)
	(In thousands, except unit amounts)
July 1, 2022 - July 31, 2022	760,000	$	26.51	760,000	$	591,618
August 1, 2022 - August 31, 2022	529,972	$	29.37	529,972	$	576,050
September 1, 2022 - September 30, 2022	527,745	$	28.44	527,745	$	561,043
Total	1,817,717	$	27.91	1,817,717