UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 2023

OR

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

Commission File Number 001-36505

Viper Energy Partners LP

(Exact Name of Registrant As Specified in Its Charter)

DE

46-5001985

(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification Number)

500 West Texas Ave.

Suite 100

Midland, TX

79701

(Address of principal executive offices)

(Zip code)

(432) 221-7400

(Registrant's telephone number, including area code)

 

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units

VNOM

The Nasdaq Stock Market LLC

(NASDAQ Global Select Market)

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

 

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

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

Large Accelerated Filer

☒

Accelerated Filer

☐

Non-Accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

As of July 28, 2023, the registrant had outstanding 70,904,057 common units representing limited partner interests and 90,709,946 Class B units representing limited partner interests.

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VIPER ENERGY PARTNERS LP

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 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			17
Item 3. Quantitative and Qualitative Disclosures about Market Risk			27
Item 4. Controls and Procedures			28
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			29
Item 1A. Risk Factors			29
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			29
Item 5. Other Information			29
Item 6. Exhibits			30
Signatures			31

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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.
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, 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.
Exchange Act			The Securities Exchange Act of 1934, as amended.
GAAP			Accounting principles generally accepted in the United States.
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.
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.

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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, 2022, could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of the Partnership and the Operating Company.

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

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

•the impact of public health crises, including epidemic or pandemic diseases 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.

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PART I. FINANCIAL INFORMATION

ITEM 1.     CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Viper Energy Partners LP

Condensed Consolidated Balance Sheets

(Unaudited)

			June 30,						December 31,
			2023						2022
			(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents			$	13,079					$	18,179
Royalty income receivable (net of allowance for credit losses)			80,765						81,657
Royalty income receivable—related party			4,384						6,260
Derivative instruments			—						9,328
Other current assets			7,566						3,196
Total current assets			105,794						118,620
Property:
Oil and natural gas interests, full cost method of accounting ($1,195,923 and $1,297,221 excluded from depletion at June 30, 2023 and December 31, 2022, respectively)			3,590,476						3,464,819
Land			5,688						5,688
Accumulated depletion and impairment			(785,286)						(720,234)
Property, net			2,810,878						2,750,273
Derivative instruments			—						442
Deferred income taxes (net of allowances)			49,124						49,656
Other assets			1,242						1,382
Total assets			$	2,967,038					$	2,920,373
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable			$	19					$	1,129
Accounts payable—related party			—						306
Accrued liabilities			18,127						19,600
Derivative instruments			8,349						—
Income taxes payable			1,584						911
Total current liabilities			28,079						21,946
Long-term debt, net			649,416						576,895
Derivative instruments			3,373						7
Total liabilities			680,868						598,848
Commitments and contingencies (Note 12)
Unitholders’ equity:
General Partner			609						649
Common units (71,206,622 units issued and outstanding as of June 30, 2023 and 73,229,645 units issued and outstanding as of December 31, 2022)			665,511						689,178
Class B units (90,709,946 units issued and outstanding as of June 30, 2023 and December 31, 2022)			782						832
Total Viper Energy Partners LP unitholders’ equity			666,902						690,659
Non-controlling interest			1,619,268						1,630,866
Total equity			2,286,170						2,321,525
Total liabilities and unitholders’ equity			$	2,967,038					$	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 June 30,												Six Months Ended June 30,
			2023						2022						2023						2022
			(In thousands, except per unit amounts)
Operating income:
Royalty income			$	158,197					$	238,830					$	319,282					$	431,919
Lease bonus income—related party			1,277						—						8,348						6,280
Lease bonus income			1,134						329						1,534						2,731
Other operating income			179						163						581						295
Total operating income			160,787						239,322						329,745						441,225
Costs and expenses:
Production and ad valorem taxes			12,621						16,039						25,508						29,909
Depletion			34,064						31,962						65,051						59,373
General and administrative expenses			2,008						1,880						4,772						3,833
Total costs and expenses			48,693						49,881						95,331						93,115
Income (loss) from operations			112,094						189,441						234,414						348,110
Other income (expense):
Interest expense, net			(11,291)						(9,782)						(20,977)						(19,427)
Gain (loss) on derivative instruments, net			(12,594)						(1,889)						(27,697)						(20,248)
Other income, net			172						32						313						38
Total other expense, net			(23,713)						(11,639)						(48,361)						(39,637)
Income (loss) before income taxes			88,381						177,802						186,053						308,473
Provision for (benefit from) income taxes			8,450						6,182						17,856						8,812
Net income (loss)			79,931						171,620						168,197						299,661
Net income (loss) attributable to non-controlling interest			49,381						137,598						103,680						249,034
Net income (loss) attributable to Viper Energy Partners LP			$	30,550					$	34,022					$	64,517					$	50,627
Net income (loss) attributable to common limited partner units:
Basic			$	0.42					$	0.44					$	0.89					$	0.66
Diluted			$	0.42					$	0.44					$	0.89					$	0.66
Weighted average number of common limited partner units outstanding:
Basic			71,771						76,620						72,249						76,861
Diluted			71,771						76,729						72,249						76,978

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, 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

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

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

(Unaudited)

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

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Cash Flows

(Unaudited)

			Six Months Ended June 30,
			2023						2022
			(In thousands)
Cash flows from operating activities:
Net income (loss)			$	168,197					$	299,661
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes			532						—
Depletion			65,051						59,373
(Gain) loss on derivative instruments, net			27,697						20,248
Net cash receipts (payments) on derivatives			(6,212)						(17,029)
Other			1,222						2,893
Changes in operating assets and liabilities:
Royalty income receivable			892						(53,876)
Royalty income receivable—related party			1,876						(8,445)
Accounts payable and accrued liabilities			(2,583)						(5,580)
Accounts payable—related party			(306)						—
Income tax payable			673						2,288
Other			(4,370)						(513)
Net cash provided by (used in) operating activities			252,669						299,020
Cash flows from investing activities:
Acquisitions of oil and natural gas interests—related party			(75,073)						—
Acquisitions of oil and natural gas interests			(48,609)						1,862
Proceeds from sale of oil and natural gas interests			(1,975)						29,336
Other			1,200						—
Net cash provided by (used in) investing activities			(124,457)						31,198
Cash flows from financing activities:
Proceeds from borrowings under credit facility			191,000						144,000
Repayment on credit facility			(119,000)						(198,000)
Repayment of senior notes			—						(48,963)
Repurchased units as part of unit buyback			(57,531)						(68,209)
Distributions to public			(58,881)						(87,084)
Distributions to Diamondback			(87,729)						(107,015)
Other			(1,171)						(83)
Net cash provided by (used in) financing activities			(133,312)						(365,354)
Net increase (decrease) in cash and cash equivalents			(5,100)						(35,136)
Cash, cash equivalents and restricted cash at beginning of period			18,179						39,448
Cash, cash equivalents and restricted cash at end of period			$	13,079					$	4,312

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements

(Unaudited)

1.    ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

As of June 30, 2023, Viper Energy Partners GP LLC (the “General Partner”) held a 100% general partner interest in the Partnership and Diamondback Energy, Inc. (“Diamondback”) beneficially owned approximately 57% of the Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner.

Basis of Presentation

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

These condensed consolidated financial statements have been prepared by the Partnership without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This report should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 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 war in Ukraine, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, and measures to combat persistent inflation and instability in the financial sector have contributed to recent pricing and economic 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

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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 June 30, 2023 and December 31, 2022, Diamondback, either directly or through its consolidated subsidiaries, owed the Partnership $4.4 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 six months ended June 30, 2023 and the six months ended June 30, 2022, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $1.3 million, $8.3 million and $6.3 million, respectively, of lease bonus income primarily related to new leases in the Midland Basin. There was no lease bonus income for the three months ended June 30, 2022.

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 as of June 30, 2023 and for the three and six months ended June 30, 2023 and 2022.

Accrued Liabilities

Accrued liabilities consist of the following:

			June 30,						December 31,
			2023						2022
			(In thousands)
Interest payable			$	4,449					$	3,972
Ad valorem taxes payable			9,963						12,492
Derivatives instruments payable			1,756						1,684
Other			1,959						1,452
Total accrued liabilities			$	18,127					$	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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3.    REVENUE FROM CONTRACTS WITH CUSTOMERS

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

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

			Three Months Ended June 30,												Six Months Ended June 30,
			2023						2022						2023						2022
			(In thousands)
Oil income			$	139,300					$	191,195					$	275,919					$	346,246
Natural gas income			5,090						23,793						14,081						38,983
Natural gas liquids income			13,807						23,842						29,282						46,690
Total royalty income			$	158,197					$	238,830					$	319,282					$	431,919

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, approximately 72% of which is from oil. 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

Additionally in the first half of 2023, the Partnership acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 203 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $48.1 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.

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 Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

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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 an aggregate net sales price of $29.3 million, including 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, including customary closing adjustments.

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.

5.    OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:

			June 30,						December 31,
			2023						2022
			(In thousands)
Oil and natural gas interests:
Subject to depletion			$	2,394,553					$	2,167,598
Not subject to depletion			1,195,923						1,297,221
Gross oil and natural gas interests			3,590,476						3,464,819
Accumulated depletion and impairment			(785,286)						(720,234)
Oil and natural gas interests, net			2,805,190						2,744,585
Land			5,688						5,688
Property, net of accumulated depletion and impairment			$	2,810,878					$	2,750,273

As of June 30, 2023 and December 31, 2022, the Partnership had mineral and royalty interests representing 27,178 and 26,315 net royalty acres, respectively.

No impairment expense was recorded on the Partnership’s oil and natural gas interests for the three and six months ended June 30, 2023 and 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:

			June 30,						December 31,
			2023						2022
			(In thousands)
5.375% senior unsecured notes due 2027			$	430,350					$	430,350
Revolving credit facility			224,000						152,000
Unamortized debt issuance costs			(1,171)						(1,306)
Unamortized discount			(3,763)						(4,149)
Total long-term debt			$	649,416					$	576,895

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The Operating Company’s Revolving Credit Facility

On May 31, 2023, the Operating Company entered into a tenth amendment to the existing credit agreement, which among other things, (i) maintained the maximum credit amount of $2.0 billion, (ii) increased the borrowing base from $580.0 million to $1.0 billion and (iii) increased the elected commitment amount from $500.0 million to $750.0 million. The borrowing base is scheduled to be redetermined semi-annually in May and November. As of June 30, 2023, the Operating Company had $224.0 million of outstanding borrowings and $526.0 million available for future borrowings. During the three and six months ended June 30, 2023 and 2022, the weighted average interest rates on the Operating Company’s revolving credit facility were 7.53%, 7.24%, 3.20% and 2.88%, respectively. The revolving credit facility will mature on June 2, 2025.

As of June 30, 2023, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement.

7.    UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has General Partner and limited partner units. At June 30, 2023, the Partnership had a total of 71,206,622 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 57% of the Partnership’s total units outstanding. At June 30, 2023, Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 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).

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 six months ended June 30, 2023 and 2022, the Partnership repurchased, excluding excise tax, approximately $24.3 million, $57.0 million, $28.9 million and $68.2 million of common units under the repurchase program, respectively. Repurchases for the six months ended June 30, 2022 include approximately $37.3 million for the repurchase of 1.5 million common units from a significant unitholder in a privately negotiated transaction in the first quarter of 2022. As of June 30, 2023, $472.4 million remains available under the repurchase program, excluding excise tax.

Cash Distributions

Effective with the Partnership’s distribution payable for the third quarter of 2022, the board of directors of the General Partner approved a distribution policy consisting of a base and variable distribution, that takes into account capital returned to unitholders via our common unit repurchase program. For a detailed description of the Partnership’s and the Operating Company’s 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 may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet while also expanding the return of capital program through the Partnership’s common unit repurchase program. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other basis.

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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 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 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

(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.

Change in Ownership of Consolidated Subsidiaries

Non-controlling interest in the accompanying condensed consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. Diamondback’s relative ownership interest in the Operating Company can change due to the Partnership’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on the Partnership’s units. These changes in ownership percentage result in adjustments to non-controlling interest and common unitholder equity, tax effected, but do not impact earnings. The following table summarizes the changes in common unitholder equity due to changes in ownership interest during the period:

			Three Months Ended June 30,												Six Months Ended June 30,
			2023						2022						2023						2022
			(In thousands)
Net income (loss) attributable to the Partnership			$	30,550					$	34,022					$	64,517					$	50,627
Change in ownership of consolidated subsidiaries			16,749						11,523						28,198						25,718
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest			$	47,299					$	45,545					$	92,715					$	76,345

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 six months ended June 30, 2023 and 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.

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

			Three Months Ended June 30,												Six Months Ended June 30,
			2023						2022						2023						2022
			(In thousands, except per unit amounts)
Net income (loss) attributable to the period			$	30,550					$	34,022					$	64,517					$	50,627
Less: distributed and undistributed earnings allocated to participating securities(1)			56						113						123						177
Net income (loss) attributable to common unitholders			$	30,494					$	33,909					$	64,394					$	50,450
Weighted average common units outstanding:
Basic weighted average common units outstanding			71,771						76,620						72,249						76,861
Effect of dilutive securities:
Potential common units issuable(2)			—						109						—						117
Diluted weighted average common units outstanding			71,771						76,729						72,249						76,978
Net income (loss) per common unit, basic			$	0.42					$	0.44					$	0.89					$	0.66
Net income (loss) per common unit, diluted			$	0.42					$	0.44					$	0.89					$	0.66

(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 six months ended June 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.

9.    INCOME TAXES

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

			Three Months Ended June 30,												Six Months Ended June 30,
			2023						2022						2023						2022
			(In thousands, except for tax rate)
Provision for (benefit from) income taxes			$	8,450					$	6,182					$	17,856					$	8,812
Effective tax rate			9.6		%				3.5		%				9.6		%				2.9		%

The Partnership’s effective income tax rate for the three and six months ended June 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 six months ended June 30, 2022 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 and the impact of maintaining a valuation allowance on the Partnership’s deferred tax assets.

As of June 30, 2023, the Partnership maintained a 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, as required by applicable accounting standards.

As of June 30, 2022, the Partnership had a full valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets.

The Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, and imposed an excise tax of 1% on the fair market value of 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’s excise tax during the three and six months ended June 30, 2023 was immaterial and is recognized as part of the cost basis of the units repurchased.

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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 June 30, 2023, the Partnership has 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.

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

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

															Swaps															Puts
Settlement Month			Settlement Year			Type of Contract			Bbls/Mcf Per Day			Index			Weighted Average Differential																		Strike Price						Deferred Premium
OIL
Jul. - Sep.			2023			Puts			12,000			WTI Cushing			$—																		$55.00						$1.80
Oct. - Dec.			2023			Puts			12,000			WTI Cushing			$—																		$55.00						$1.85
Jul. - Dec.			2023			Basis Swaps			4,000			Argus WTI Midland			$1.05																		$—						$—
NATURAL GAS
Jul. - 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 June 30,												Six Months Ended June 30,
			2023						2022						2023						2022
			(In thousands)
Gain (loss) on derivative instruments			$	(12,594)					$	(1,889)					$	(27,697)					$	(20,248)
Net cash receipts (payments) on derivatives(1)			$	(3,997)					$	(6,765)					$	(6,212)					$	(17,029)

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

11.    FAIR VALUE MEASUREMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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 inputs 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 June 30, 2023 and December 31, 2022:

			As of June 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
			(In thousands)
Assets:
Current:
Derivative instruments			$	—		$	1,541		$	—		$	1,541		$	(1,541)		$	—
Liabilities:
Current:
Derivative instruments			$	—		$	9,890		$	—		$	9,890		$	(1,541)		$	8,349
Non-current:
Derivative instruments			$	—		$	3,373		$	—		$	3,373		$	—		$	3,373

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			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
			(In thousands)
Assets:
Current:
Derivative instruments			$	—		$	13,296		$	—		$	13,296		$	(3,968)		$	9,328
Non-current:
Derivative instruments			$	—		$	1,911		$	—		$	1,911		$	(1,469)		$	442
Liabilities:
Current:
Derivative instruments			$	—		$	3,968		$	—		$	3,968		$	(3,968)		$	—
Non-current:
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:

			June 30, 2023												December 31, 2022
			Carrying Value						Fair Value						Carrying Value						Fair Value
			(In thousands)
Debt:
Revolving credit facility			$	224,000					$	224,000					$	152,000					$	152,000
5.375% senior notes due 2027(1)			$	425,416					$	413,097					$	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 June 30, 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, other current assets, accounts payable, accrued liabilities and 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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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

Cash Distribution

On July 25, 2023, the board of directors of the General Partner approved an increase to the Partnership’s annual base dividend to $1.08 per common unit beginning with the distribution payable for the second quarter of 2023, and a cash distribution for the second quarter of 2023 of $0.36 per common unit and $0.44 per Class B unit, payable on August 17, 2023, to eligible unitholders of record at the close of business on August 10, 2023. For the second quarter of 2023, the distribution to common unitholders consists of a base quarterly distribution of $0.27 per common unit and a variable quarterly distribution of $0.09 per common unit.

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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, 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

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 first half of 2023 and 2022, the NYMEX WTI price averaged $74.77 and $101.77 per Bbl, respectively, and NYMEX Henry Hub price averaged $2.54 and $6.04 per MMBtu, respectively. The war in Ukraine, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility 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.

Cash Distribution Update

On July 25, 2023, the board of directors of the General Partner approved an increase to the Partnership’s annual base dividend to $1.08 per common unit beginning with our distribution payable for the second quarter of 2023.

Intent to Convert into Corporate Structure

On July 31, 2023, we announced our intent to convert our legal status from a Delaware limited partnership into a Delaware corporation. The conversion is expected to be completed by or before December 31, 2023. After the conversion, it is expected that our current limited partners would own the same percentage of the corporation’s outstanding shares as they currently own of the Partnership’s outstanding equity interests.

In connection with the conversion, we intend to adopt a corporate governance structure designed to meet the eligibility requirements for certain indices and benchmarks, which we believe would further broaden our investor base and improve our trading liquidity, although no assurances can be provided regarding inclusion in any such index or benchmark. Because we are already treated as a corporation for U.S. federal income tax purposes, we expect that the conversion of our entity form into a Delaware corporation will not impact the current tax treatment for the Partnership’s current public common unitholders.

Upon conversion, it is intended that our common stockholders will have the ability to vote on all matters on which stockholders of a corporation are generally entitled to vote under the Delaware General Corporation Law, including the election of our board of directors. Immediately following the proposed conversion, we would be a “controlled company” under the Nasdaq rules because Diamondback would own more than 50% of the voting power of our common stock. In addition, Diamondback intends to continue to provide general and administrative services to us post-conversion in substantially the same manner as Diamondback currently provides. At or around the actual conversion, we intend to provide additional information regarding the post-conversion structural arrangements, including the terms of our post-conversion governing documents and the arrangements providing for Diamondback’s provision of services to us post-conversion. It is expected that post-conversion, our publicly traded common stock will be traded on Nasdaq under the existing ticker symbol “VNOM.”

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Production and Operational Update

Our footprint of mineral and royalty interests totaled 27,178 net royalty acres, approximately 58% of which are operated by Diamondback, as of June 30, 2023. Continuing the trend of increasing production, average oil production per day during the second quarter of 2023 was the highest in the Partnership’s history. There are currently 47 rigs operating on our mineral and royalty acreage, eight of which are operated by Diamondback. As a result of the continued outperformance of our production goals, we have increased our third quarter 2023 oil production guidance by approximately four percent at midpoint compared to average daily oil production in the second quarter of 2023. Due to 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 by over 15% compared to 2022, with a further increase of approximately 10% expected for the full year 2024.

The following table summarizes our gross well information for the second quarter ended June 30, 2023:

			Diamondback Operated						Third Party Operated						Total
Horizontal wells turned to production(1):
Gross wells			81						204						285
Net 100% royalty interest wells			3.9						2.0						5.9
Average percent net royalty interest			4.8		%				1.0		%				2.1		%
Horizontal producing well count:
Gross wells			1,653						4,189						5,842
Net 100% royalty interest wells			120.8						68.1						188.9
Average percent net royalty interest			7.3		%				1.6		%				3.2		%
Horizontal active development well count(2):
Gross wells			110						353						463
Net 100% royalty interest wells			6.5						2.9						9.4
Average percent net royalty interest			5.9		%				0.8		%				2.0		%
Line of sight wells(3):
Gross wells			206						371						577
Net 100% royalty interest wells			12.3						5.6						17.9
Average percent net royalty interest			6.0		%				1.5		%				3.1		%

(1) Average lateral length of 11,403.

(2) The total 463 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 577 gross line-of-sight wells are those that are not currently in the process of active development, but for which we have reason to believe that they will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices.

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Comparison of the Three Months Ended June 30, 2023 and March 31, 2023

Results of Operations

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

			Three Months Ended
			June 30, 2023						March 31, 2023
			(In thousands)
Operating income:
Oil income			$	139,300					$	136,619
Natural gas income			5,090						8,991
Natural gas liquids income			13,807						15,475
Royalty income			158,197						161,085
Lease bonus income—related party			1,277						7,071
Lease bonus income			1,134						400
Other operating income			179						402
Total operating income			160,787						168,958
Costs and expenses:
Production and ad valorem taxes			12,621						12,887
Depletion			34,064						30,987
General and administrative expenses			2,008						2,764
Total costs and expenses			48,693						46,638
Income (loss) from operations			112,094						122,320
Other income (expense):
Interest expense, net			(11,291)						(9,686)
Gain (loss) on derivative instruments, net			(12,594)						(15,103)
Other income, net			172						141
Total other expense, net			(23,713)						(24,648)
Income (loss) before income taxes			88,381						97,672
Provision for (benefit from) income taxes			8,450						9,406
Net income (loss)			79,931						88,266
Net income (loss) attributable to non-controlling interest			49,381						54,299
Net income (loss) attributable to Viper Energy Partners LP			$	30,550					$	33,967

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

			Three Months Ended
			June 30, 2023						March 31, 2023
Production data:
Oil (MBbls)			1,924						1,810
Natural gas (MMcf)			4,685						4,224
Natural gas liquids (MBbls)			724						633
Combined volumes (MBOE)(1)			3,429						3,147
Average daily oil volumes (BO/d)			21,143						20,111
Average daily combined volumes (BOE/d)			37,681						34,967
Average sales prices:
Oil ($/Bbl)			$	72.40					$	75.48
Natural gas ($/Mcf)			$	1.09					$	2.13
Natural gas liquids ($/Bbl)			$	19.07					$	24.45
Combined ($/BOE)(2)			$	46.14					$	51.19
Oil, hedged ($/Bbl)(3)			$	71.39					$	74.30
Natural gas, hedged ($/Mcf)(3)			$	0.65					$	2.11
Natural gas liquids ($/Bbl)(3)			$	19.07					$	24.45
Combined price, hedged ($/BOE)(3)			$	44.97					$	50.48
Average costs ($/BOE):
Production and ad valorem taxes			$	3.68					$	4.10
General and administrative - cash component(4)			0.51						0.76
Total operating expense - cash			$	4.19					$	4.86
General and administrative - non-cash unit compensation expense			$	0.08					$	0.12
Interest expense, net			$	3.29					$	3.08
Depletion			$	9.93					$	9.85

(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 $2.9 million during the second quarter of 2023 compared to the first quarter of 2023. Changes in average pricing contributed to approximately $14.7 million of the total decrease due to lower average prices for oil, natural gas and natural gas liquids received for our production in the second quarter of 2023. The impact of lower pricing was partially offset by an increase of $11.8 million in royalty income due to 9% growth in production in the second quarter of 2023 compared to the first 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 decreased $5.8 million due primarily to receiving payment for two leases and two lease extensions covering approximately 165 net mineral acres in the second quarter of 2023 compared to receiving payment for one lease covering approximately 257 net mineral acres in Martin County, TX from Diamondback in the first quarter of 2023.

Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the three months ended June 30, 2023 and March 31, 2023:

			Three Months Ended
			June 30, 2023																		March 31, 2023
			Amount (In thousands)						Per BOE						Percentage of Royalty Income						Amount (In thousands)						Per BOE						Percentage of Royalty Income
Production taxes			$	7,807					$	2.28					5.0		%				$	8,177					$	2.60					5.1		%
Ad valorem taxes			4,814						1.40						3.0						4,710						1.50						2.9
Total production and ad valorem taxes			$	12,621					$	3.68					8.0		%				$	12,887					$	4.10					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 second quarter of 2023 were consistent with the first quarter of 2023. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices, and were also consistent for the second quarter of 2023 compared to the first quarter of 2023.

Depletion

The $3.1 million increase in depletion expense for the second quarter of 2023 compared to the first quarter of 2023 was due primarily to production growth between the periods. The average depletion rate also increased slightly to $9.93 per BOE for the second quarter of 2023 compared to $9.85 per BOE for the first 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
			June 30, 2023						March 31, 2023
			(In thousands)
Gain (loss) on derivative instruments			$	(12,594)					$	(15,103)
Net cash receipts (payments) on derivatives			$	(3,997)					$	(2,215)

We recorded losses on our derivative instruments for the three months ended June 30, 2023 and March 31, 2023 primarily due to a decrease in the differential spread compared to contract terms on our natural gas basis swaps. 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 June 30, 2023.

Provision for (Benefit from) Income Taxes

The $1.0 million decrease in income tax expense for the second quarter of 2023 compared to the first quarter of 2023 is primarily due to the decrease in pre-tax income attributable to the Partnership. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements for further details.

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Comparison of the Six Months Ended June 30, 2023 and 2022

Results of Operations

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

			Six Months Ended June 30,
			2023						2022
Operating income:
Oil income			$	275,919					$	346,246
Natural gas income			14,081						38,983
Natural gas liquids income			29,282						46,690
Royalty income			319,282						431,919
Lease bonus income—related party			8,348						6,280
Lease bonus income			1,534						2,731
Other operating income			581						295
Total operating income			329,745						441,225
Costs and expenses:
Production and ad valorem taxes			25,508						29,909
Depletion			65,051						59,373
General and administrative expenses			4,772						3,833
Total costs and expenses			95,331						93,115
Income (loss) from operations			234,414						348,110
Other income (expense):
Interest expense, net			(20,977)						(19,427)
Gain (loss) on derivative instruments, net			(27,697)						(20,248)
Other income, net			313						38
Total other expense, net			(48,361)						(39,637)
Income (loss) before income taxes			186,053						308,473
Provision for (benefit from) income taxes			17,856						8,812
Net income (loss)			168,197						299,661
Net income (loss) attributable to non-controlling interest			103,680						249,034
Net income (loss) attributable to Viper Energy Partners LP			$	64,517					$	50,627

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

			Six Months Ended June 30,
			2023						2022
Production data:
Oil (MBbls)			3,734						3,431
Natural gas (MMcf)			8,909						7,627
Natural gas liquids (MBbls)			1,357						1,193
Combined volumes (MBOE)(1)			6,576						5,895
Average daily oil volumes (BO/d)			20,630						18,956
Average daily combined volumes (BOE/d)			36,331						32,569
Average sales prices:
Oil ($/Bbl)			$	73.89					$	100.92
Natural gas ($/Mcf)			$	1.58					$	5.11
Natural gas liquids ($/Bbl)			$	21.58					$	39.14
Combined ($/BOE)(2)			$	48.55					$	73.27
Oil, hedged ($/Bbl)(3)			$	72.80					$	99.14
Natural gas, hedged ($/Mcf)(3)			$	1.34					$	4.22
Natural gas liquids ($/Bbl)(3)			$	21.58					$	39.14
Combined price, hedged ($/BOE)(3)			$	47.61					$	71.09
Average costs ($/BOE):
Production and ad valorem taxes			$	3.88					$	5.07
General and administrative - cash component(4)			0.63						0.55
Total operating expense - cash			$	4.51					$	5.62
General and administrative - non-cash unit compensation expense			$	0.10					$	0.11
Interest expense, net			$	3.19					$	3.30
Depletion			$	9.89					$	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 decreased $112.6 million during the six months ended June 30, 2023 compared to the same period in 2022. Changes in average pricing during 2023 contributed to approximately $156.2 million of the total decrease due primarily to lower average oil prices, natural gas and natural gas liquids prices received for our production in 2023. The decrease due to lower pricing was partially offset by $43.5 million in additional royalty income due to a 12% increase in production volumes during the six months ended June 30, 2023 compared to the same period in 2022. This production growth stems from new well development in areas where Viper has a higher royalty interest between periods.

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Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the six months ended June 30, 2023 and 2022:

			Six Months Ended June 30,
			2023																		2022
			Amount (In thousands)						Per BOE						Percentage of Royalty Income						Amount (In thousands)						Per BOE						Percentage of Royalty Income
Production taxes			$	15,984					$	2.43					5.0		%				$	21,894					$	3.71					5.1		%
Ad valorem taxes			9,524						1.45						3.0						8,015						1.36						1.9
Total production and ad valorem taxes			$	25,508					$	3.88					8.0		%				$	29,909					$	5.07					7.0		%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of royalty income for the six months ended June 30, 2023 remained consistent with the same period in 2022. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. The increase in ad valorem taxes is primarily due to higher valuations assigned to our oil and natural gas interests period over period driven by higher average commodity prices in 2022.

Depletion

The $5.7 million increase in depletion expense for the six months ended June 30, 2023 compared to the same period in 2022 was due primarily to production growth between the periods resulting largely from new well development. The average depletion rate decreased slightly to $9.89 for the six months ended June 30, 2023 compared to the rate of $10.07 for the same period in 2022 due primarily to lower value leasehold being transferred into the amortization base during 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:

			Six Months Ended June 30,
			2023						2022
			(In thousands)
Gain (loss) on derivative instruments			$	(27,697)					$	(20,248)
Net cash receipts (payments) on derivatives(1)			$	(6,212)					$	(17,029)

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

We recorded losses on our derivative instruments for the six months ended June 30, 2023 and 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. See Note 10—Derivatives of the notes to the condensed consolidated financial statements for additional discussion of our open contracts at June 30, 2023.

Provision for (Benefit from) Income Taxes

The $9.0 million increase in income tax expense for the six months ended June 30, 2023 compared to the same period in 2022 resulted primarily from the increase in pre-tax income attributable to the Partnership as a result of the expiration of the special income allocation at December 31, 2022 and the impact of maintaining a valuation allowance against the Partnership’s deferred tax assets as of June 30, 2022. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements for further details.

Net Income (Loss) Attributable to Non-controlling Interest

The $145.4 million decrease in net income (loss) attributable to non-controlling interest for the six months ended June 30, 2023 compared to the same period in 2022 is primarily due to the expiration of the special income allocation at December 31, 2022.

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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, equity and debt offerings and borrowings under the Operating Company’s credit agreement. Our primary uses of cash have been distributions to our unitholders, repayments of debt, capital expenditures for the acquisition of our mineral and royalty interests in oil and natural gas properties and repurchases of our common units. At June 30, 2023, we had approximately $539.1 million of liquidity consisting of $13.1 million in cash and cash equivalents and $526.0 million available under the Operating Company’s credit agreement.

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

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

Continued prolonged volatility in the capital, financial and/or credit markets due to the war in Ukraine, the depressed commodity markets 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.

Cash Flows

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

			Six Months Ended June 30,
			2023						2022
			(In thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities			$	252,669					$	299,020
Net cash provided by (used in) investing activities			(124,457)						31,198
Net cash provided by (used in) financing activities			(133,312)						(365,354)
Net increase (decrease) in cash and cash equivalents			$	(5,100)					$	(35,136)

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 decrease in net cash provided by operating activities during the six months ended June 30, 2023 compared to the same period in 2022 was primarily driven by lower royalty income. This was partially offset by an increase in cash flows from (i) changes in our working capital accounts, due primarily to a reduction in our royalty income receivables at June 30, 2023 compared to June 30, 2022 resulting from lower commodity prices and royalty income in 2023, (ii) a decrease in cash paid for derivative settlements, and (iii) a reduction in production and ad valorem taxes due to the corresponding decrease in royalty income. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

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Investing Activities

Net cash used in investing activities during the six months ended June 30, 2023 primarily related to the acquisition of oil and natural gas interests in the Drop Down and from other third-party acquisitions.

Net cash provided by in investing activities during the six months ended June 30, 2022 primarily related to proceeds from the divestiture of oil and natural gas interests.

Financing Activities

Net cash used in financing activities during the six months ended June 30, 2023 primarily resulted from distributions of $146.6 million and $57.5 million of common unit repurchases as we continue to return capital to our unitholders. These cash outflows were partially offset by net borrowings of $72.0 million under the Operating Company’s revolving credit facility.

Net cash used in financing activities during the six months ended June 30, 2022, was primarily related to distributions of $194.1 million to our unitholders and $68.2 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 $49.0 million for the repurchase of principal outstanding on the Notes and made net repayments of $54.0 million under the Operating Company’s revolving credit facility.

Capital Resources

The Operating Company’s Revolving Credit Facility

During the second quarter of 2023, the Operating Company entered into a tenth amendment to our existing credit agreement, which strengthened our short and long-term liquidity positions by among other things, increasing our borrowing base from $580.0 million to $1.0 billion, and increasing our elected commitment amount from $500.0 million to $750.0 million. The Operating Company’s credit agreement, which matures on June 2, 2025, had $224.0 million in outstanding borrowings and $526.0 million of availability at June 30, 2023.

See Note 6—Debt of the notes to the condensed consolidated financial statements for additional discussion of our outstanding debt at June 30, 2023.

Capital Requirements

Repurchases of Securities

Under our current common unit repurchase program, the board of directors of our General Partner has authorized us to acquire up to $750.0 million of our common units, excluding excise tax. As of June 30, 2023, $472.4 million remains available for use to repurchase units under this repurchase 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 distribution for the second quarter of 2023 is $0.36 per common unit and $0.44 per Class B unit payable on August 17, 2023 to eligible unitholders of record at the close of business on August 10, 2023. The dividend to common unitholders consists of a base quarterly dividend of $0.27 per common unit and a variable quarterly dividend of $0.09 per common unit.

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

See Note 7—Unitholders' Equity and Distributions of the notes to the condensed consolidated financial statements 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, 2022.

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Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies included in the condensed notes to the consolidated financial statements 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.

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, rising interest rates, global supply chain disruptions, a potential economic downturn or recession and actions taken by OPEC members and other exporting nations. We cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.

We historically have used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our royalty income as discussed in Note 10—Derivatives of the notes to the condensed consolidated financial statements.

At June 30, 2023, we had a net liability derivative position related to our commodity price derivatives of $11.7 million. Utilizing actual derivative contractual volumes under our contracts as of June 30, 2023, a 10% increase in forward curves associated with the underlying commodity would have decreased the net liability position by $0.4 million to approximately $11.4 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net liability derivative position by $0.3 million to approximately $12.0 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Credit Risk

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

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under the Operating Company’s credit agreement. The terms of the credit agreement provide for interest on borrowings at a floating rate equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”) or (ii) an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month Adjusted Term SOFR plus 1.00%), 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 Adjusted Term SOFR, in each case depending on the amount of the loans outstanding in relation to the commitment, which is calculated using the least of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment. As of June 30, 2023, we had $224.0 million in outstanding borrowings. During the three and six months ended June 30, 2023, the weighted average interest rate on the Operating Company’s revolving credit facility was 7.53% and 7.24%.

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ITEM 4.          CONTROLS AND PROCEDURES

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

As of June 30, 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 June 30, 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 June 30, 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, 2022, filed with the SEC on February 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 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 June 30, 2023 was as follows:

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)
April 1, 2023 - April 30, 2023						102,000						$	29.27					102,000						$	493,700
May 1, 2023 - May 31, 2023						379,500						$	26.91					379,500						$	483,487
June 1, 2023 - June 30, 2023						430,500						$	25.71					430,500						$	472,420
Total						912,000						$	26.61					912,000

(1)The average price paid per common unit includes any commissions paid to repurchase a common unit.

(2)On July 26, 2022, the board of directors of our General Partner increased the authorization under our then-in-effect common unit repurchase program from $250.0 million to $750.0 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 June 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).
3.1						Certificate of Limited Partnership of Viper Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File 333-195769) filed on May 7, 2014).
3.2						Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 9, 2018 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.3						First Amendment to Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 10, 2018. (incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.4						Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of May 9, 2018. (incorporated by reference to Exhibit 3.3 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.5						First Amendment to Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of March 30, 2020 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on March 31, 2020).
3.6						Second Amendment to the Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of December 27, 2021 (incorporated by reference to 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 1, 2021, by and among Viper Energy Partners LP, Swallowtail Royalties LLC and Swallowtail Royalties II LLC (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on October 7, 2021).
10.1						Tenth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement and Second Amendment to Guaranty and Collateral Agreement, dated as of May 31, 2023, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership's Current Report on Form 8-K (File No. 001-36505) filed on June 6, 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 June 30, 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:			August 3, 2023			By:			/s/ Travis D. Stice
									Travis D. Stice
									Chief Executive Officer
Date:			August 3, 2023			By:			/s/ Teresa L. Dick
									Teresa L. Dick
									Chief Financial Officer

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