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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

ý☒QUARTERLY REPORT UNDERPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SeptemberFor the Quarterly Period Ended June 30, 20172023
OR
o

☐		TRANSITION REPORT UNDERPURSUANT 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)
Delaware
DE46-5001985
(State or Other Jurisdiction of
Incorporation or Organization)
(IRSI.R.S. Employer
Identification Number)
500 West Texas Suite 1200
Midland, Texas
Ave.		79701
Suite 100
Midland, TX79701
(Address of Principal Executive Offices)principal executive offices)(Zip Code)code)
(432) 221-7400
(Registrant Telephone Number, Including Area Code)Registrant's telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsVNOMThe 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 pastpreceding 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.    Yesý☒No¨☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yesý☒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☐
Large Accelerated FileroAccelerated Filerý
Non-Accelerated FileroSmaller Reporting Companyo
Emerging Growth Companyý☐

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.    ý☐


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes¨☐     Noý☒


As of October 20, 2017, 113,882,045July 28, 2023, the registrant had outstanding 70,904,057 common units representing limited partner interests and 90,709,946 Class B units of the registrant were outstanding.representing limited partner interests.



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VIPER ENERGY PARTNERS LP
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBERJUNE 30, 20172023
TABLE OF CONTENTS
Page
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PART I. FINANCIAL INFORMATION
1
Condensed Consolidated Balance Sheets
1
Condensed Consolidated Statements of Operations
2
Condensed Consolidated Statements of Changes to Unitholders’ Equity
3
Condensed Consolidated Statements of Cash Flows
45
Condensed Notes to Consolidated Financial Statements
56
1217
2127
2128
PART II. OTHER INFORMATION
2229
2229
29
29
2230
2331




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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”):
BasinArgus WTI MidlandGrade of oil that serves as a benchmark price for oil at Midland, Texas.
BasinA large depression on the earth’s surface in which sediments accumulate.
Bbl or barrelStockOne stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOEBarrels
BOOne barrel of oil.
BO/dBO per day.
BOEOne barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/dBOE per day.
British Thermal Unit or BtuThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CompletionThe process of treating a drilled well followed by the installation of permanent equipment for
CondensateLiquid hydrocarbons associated with the production of a primarily natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.reserve.
Crude oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Gross acres or gross wellsThe total acres or wells, as the case may be, in which a working interest is owned.
Henry HubNatural gas gathering point that serves as a benchmark price for natural gas futures on the NYMEX.
Horizontal wellsWells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBOE
MBblsThousand barrels of crude oil or other liquid hydrocarbons.
MBOEOne 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.
McfThousandOne thousand cubic feet of natural gas.
MMBtuMillion
Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtuOne million British Thermal Units.
Net acres or net wellsMMcfThe sumMillion cubic feet of the fractional working interest owned in gross acres.natural gas.
Net royalty acresNet mineral acres multiplied by the average lease royalty interest and other burdens.
Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.
ProspectOperatorA specific geographic area which, based on supporting geological, geophysicalThe individual or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potentialcompany responsible for the discoveryexploration and/or production of commercial hydrocarbons.an oil or natural gas well or lease.
Proved reservesThe 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
ReservesThe 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).
ReservoirA 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 interestAn interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.development, which may be subject to expiration.
WellboreSpudThe hole drilled by the bitCommencement of actual drilling operations.
Waha HubNatural gas gathering point that serves as a benchmark price for natural gas at western Texas and New Mexico.
WTIWest Texas Intermediate, a light sweet blend of oil produced from fields in western Texas and is equippeda grade of oil that serves as a benchmark for oil or natural gas production on a completed well.the NYMEX.
Working interestWTI CushingAn operating interestGrade of oil that gives the owner the right to drill, produce and conduct operating activities on the property and receiveserves as a share of production and requires the owner to pay a share of the costs of drilling and production operations.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:
DiamondbackDiamondback Energy, Inc., a Delaware corporation.
ASUAccounting Standards Update.
Exchange ActThe Securities Exchange Act of 1934, as amended.
GAAPAccounting principles generally accepted in the United States.
General PartnerViper Energy Partners GP LLC, a Delaware limited liability company, and the General Partner of the Partnership.
IPOThe Partnership’s initial public offering.
LTIP
LTIPViper Energy Partners LP Long Term Incentive Plan.
PartnershipNasdaqViper Energy Partners LP, a Delaware limited partnership.The Nasdaq Global Select Market.
Partnership agreementNYMEXThe first amended and restated agreement of limited partnership, dated June 23, 2014, entered into by the General Partner and Diamondback in connection with the closingNew York Mercantile Exchange.
OPECOrganization of the IPO.Petroleum Exporting Countries.
PredecessorOperating CompanyViper Energy Partners LLC, a Delaware limited liability company and a wholly ownedconsolidated subsidiary of the Partnership.Viper Energy Partners LP.
SEC
SECUnited States Securities and Exchange Commission.
Securities Act
SOFRThe secured overnight financing rate
NotesThe Securities Act of 1933, as amended.5.375% Senior Notes due 2027 issued on October 16, 2019.
Wells FargoWells Fargo Bank, National Association.



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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS


Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements“forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements are subject to a number ofAct, which involve risks, uncertainties, and uncertainties, many of which are beyond our control.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 strategy, future operations, financial position, estimated revenuesability to replace or increase reserves; our intent to convert into a corporate structure and losses, projected costs, prospects,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 “could,“aim,” “anticipate,” “believe,” “anticipate,“continue,” “intend,“could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “continue,“model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “potential,“project,” “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 including thoseand detailed underPart II. Item 1A. Risk Factors in this report,, 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.


Forward-looking statements mayFactors that could cause the outcomes to differ materially include statements about:(but are not limited to) the following:
our ability to execute our business strategies;
the volatility of realized•changes in supply and demand levels for oil, natural gas, and natural gas prices;liquids, and the resulting impact on the price for those commodities;
•the levelimpact 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 on our properties;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;production on our mineral and royalty acreage, or governmental orders, rules or regulations that impose production limits on such acreage;
our ability to replace our oil and natural gas reserves;
our ability to identify, complete and integrate acquisitions of properties or businesses, including our recent and pending acquisitions;
general economic, business or industry conditions;
competition in the oil and natural gas industry;
the ability of our operators to obtain capital or financing needed for development and exploration operations;
title defects in the properties in which we invest;
uncertainties with respect to identified drilling locations and estimates of reserves;
the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;
restrictions on the use of water;
the availability of transportation facilities;
the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
•federal and state legislative and regulatory initiatives relating to hydraulic fracturing;fracturing, including the effect of existing and future laws and governmental regulations;
future operating results;•physical and transition risks relating to climate change;
exploration•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 drilling prospects, inventories, projects and programs;
operating hazards faced by our operators and environmental and social responsibility projects undertaken by Diamondback and our other operators; and
•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 abilityimpact 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 keep pace with technological advancements.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 securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.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,
20232022
(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 party4,384 6,260 
Derivative instruments— 9,328 
Other current assets7,566 3,196 
Total current assets105,794 118,620 
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 
Land5,688 5,688 
Accumulated depletion and impairment(785,286)(720,234)
Property, net2,810,878 2,750,273 
Derivative instruments— 442 
Deferred income taxes (net of allowances)49,124 49,656 
Other assets1,242 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 liabilities18,127 19,600 
Derivative instruments8,349 — 
Income taxes payable1,584 911 
Total current liabilities28,079 21,946 
Long-term debt, net649,416 576,895 
Derivative instruments3,373 7 
Total liabilities680,868 598,848 
Commitments and contingencies (Note 12)
Unitholders’ equity:
General Partner609 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’ equity666,902 690,659 
Non-controlling interest1,619,268 1,630,866 
Total equity2,286,170 2,321,525 
Total liabilities and unitholders’ equity$2,967,038 $2,920,373 



 September 30,December 31,
 20172016
   
 (In thousands, except unit amounts)
Assets  
Current assets:  
Cash and cash equivalents$4,438
$9,213
Restricted cash—
500
Royalty income receivable17,199
10,043
Royalty income receivable—related party3,646
3,470
Other current assets147
187
Total current assets25,430
23,413
Property and equipment:  
Oil and natural gas interests, full cost method of accounting ($487,899 and $252,232 excluded from depletion at September 30, 2017 and December 31, 2016, respectively)1,065,392
760,818
Accumulated depletion and impairment(177,534)(148,948)
Oil and natural gas interests, net887,858
611,870
Other assets34,929
35,266
Total assets$948,217
$670,549
Liabilities and Unitholders’ Equity  
Current liabilities:  
Accounts payable$110
$1,780
Other accrued liabilities2,747
371
Total current liabilities2,857
2,151
Long-term debt35,500
120,500
Total liabilities38,357
122,651
Commitments and contingencies (Note 10)

Unitholders’ equity:  
Common units (113,882,045 units issued and outstanding as of September 30, 2017 and 87,800,356 units issued and outstanding as of December 31, 2016 )909,860
547,898
Total unitholders’ equity909,860
547,898
Total liabilities and unitholders’ equity$948,217
$670,549















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,
2023202220232022
(In thousands, except per unit amounts)
Operating income:
Royalty income$158,197 $238,830 $319,282 $431,919 
Lease bonus income—related party1,277 — 8,348 6,280 
Lease bonus income1,134 329 1,534 2,731 
Other operating income179 163 581 295 
Total operating income160,787 239,322 329,745 441,225 
Costs and expenses:
Production and ad valorem taxes12,621 16,039 25,508 29,909 
Depletion34,064 31,962 65,051 59,373 
General and administrative expenses2,008 1,880 4,772 3,833 
Total costs and expenses48,693 49,881 95,331 93,115 
Income (loss) from operations112,094 189,441 234,414 348,110 
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, net172 32 313 38 
Total other expense, net(23,713)(11,639)(48,361)(39,637)
Income (loss) before income taxes88,381 177,802 186,053 308,473 
Provision for (benefit from) income taxes8,450 6,182 17,856 8,812 
Net income (loss)79,931 171,620 168,197 299,661 
Net income (loss) attributable to non-controlling interest49,381 137,598 103,680 249,034 
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:
Basic71,771 76,620 72,249 76,861 
Diluted71,771 76,729 72,249 76,978 

 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
 (In thousands, except per unit amounts)
Operating income:     
Royalty income$42,211
$19,992
 $110,194
$50,914
Lease bonus322
5
 2,613
309
Total operating income42,533
19,997
 112,807
51,223
Costs and expenses:     
Production and ad valorem taxes2,825
1,429
 7,668
4,134
Gathering and transportation205
70
 492
247
Depletion11,068
6,751
 28,587
21,485
Impairment—
—
 —
47,469
General and administrative expenses1,368
1,153
 5,064
4,109
Total costs and expenses15,466
9,403
 41,811
77,444
Income (loss) from operations27,067
10,594
 70,996
(26,221)
Other income (expense):     
Interest expense(859)(658) (2,114)(1,544)
Other income399
266
 526
612
Total other income (expense), net(460)(392) (1,588)(932)
Net income (loss)$26,607
$10,202
 $69,408
$(27,153)
      
Net income attributable to common limited partners per unit:     
Basic and Diluted$0.24
$0.12
 $0.69
$(0.33)
Weighted average number of limited partner units outstanding:     
Basic110,377
84,996
 101,095
81,496
Diluted110,424
85,003
 101,143
81,496

































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 PartnersGeneral PartnerNon-Controlling Interest
CommonClass BAmountAmount
UnitsAmountUnitsAmountTotal
(In thousands)
Balance at December 31, 202273,230 $689,178 90,710 $832 $649 $1,630,866 $2,321,525 
Unit-based compensation— 370 — — — — 370 
Vesting of restricted stock units4 — — — — — — 
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, 202372,119 666,259 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, 202371,207 $665,511 90,710 $782 $609 $1,619,268 $2,286,170 

 Limited Partners
 Common  
 Units Amount
   (In thousands)
Balance at December 31, 201579,726
 $495,144
Net proceeds from the issuance of common units - public6,050
 93,564
Net proceeds from the issuance of common units - Diamondback2,000
 31,200
Unit-based compensation24
 2,974
Distributions to public
 (6,397)
Distributions to Diamondback
 (40,253)
Net loss
 (27,153)
Balance at September 30, 201687,800
 $549,079
    
Balance at December 31, 201687,800
 $547,898
Net proceeds from the issuance of common units - public25,175
 369,896
Net proceeds from the issuance of common units - Diamondback700
 10,067
Common units issued for acquisition175
 3,050
Unit-based compensation32
 2,039
Distributions to public
 (27,640)
Distributions to Diamondback
 (64,858)
Net income
 69,408
Balance at September 30, 2017113,882
 $909,860












































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 PartnersGeneral PartnerNon-Controlling Interest
CommonClass BAmountAmount
UnitsAmountUnitsAmountTotal
(In thousands)
Balance at December 31, 202178,546 $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, 202276,966 768,747 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, 202275,946 $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,
20232022
(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 taxes532 — 
Depletion65,051 59,373 
(Gain) loss on derivative instruments, net27,697 20,248 
Net cash receipts (payments) on derivatives(6,212)(17,029)
Other1,222 2,893 
Changes in operating assets and liabilities:
Royalty income receivable892 (53,876)
Royalty income receivable—related party1,876 (8,445)
Accounts payable and accrued liabilities(2,583)(5,580)
Accounts payable—related party(306)— 
Income tax payable673 2,288 
Other(4,370)(513)
Net cash provided by (used in) operating activities252,669 299,020 
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 
Other1,200 — 
Net cash provided by (used in) investing activities(124,457)31,198 
Cash flows from financing activities:
Proceeds from borrowings under credit facility191,000 144,000 
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 period18,179 39,448 
Cash, cash equivalents and restricted cash at end of period$13,079 $4,312 

 Nine Months Ended September 30,
 20172016
 (In thousands)
Cash flows from operating activities:  
Net income (loss)$69,408
$(27,153)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:  
Depletion28,587
21,485
Impairment—
47,469
Amortization of debt issuance costs434
280
Non-cash unit-based compensation2,039
2,974
Changes in operating assets and liabilities:  
Restricted cash500
—
Royalty income receivable(7,156)(549)
Royalty income receivable—related party(176)—
Accounts payable—related party—
(4)
Accounts payable and other accrued liabilities367
1,707
Other current assets54
345
Net cash provided by operating activities94,057
46,554
Cash flows from investing activities:  
Acquisition of mineral interests(301,133)(137,786)
Net cash used in investing activities(301,133)(137,786)
Cash flows from financing activities:  
Proceeds from borrowings under credit facility220,500
98,000
Repayment on credit facility(305,500)(78,000)
Debt issuance costs(180)(35)
Proceeds from public offerings380,412
125,580
Public offering costs(433)(444)
Distributions to partners(92,498)(46,650)
Net cash provided by financing activities202,301
98,451
Net increase (decrease) in cash(4,775)7,219
Cash and cash equivalents at beginning of period9,213
539
Cash and cash equivalents at end of period$4,438
$7,758
   
Supplemental disclosure of cash flow information:  
Interest paid, net of capitalized interest$1,781
$1,251























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 the common units of which are listedfocused on the NASDAQ Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”) on February 27, 2014 to, among other things, own, acquireowning and exploitacquiring mineral interests and royalty interests in oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas propertiesprimarily in the Permian Basin. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of Viper Energy Partners LP and its consolidated subsidiary, Viper Energy Partners LLC.


As of SeptemberJune 30, 2017,2023, Viper Energy Partners GP LLC (the “General Partner”), held a 100% non-economic general partner interest in the Partnership and Diamondback had an approximate 64%Energy, Inc. (“Diamondback”) beneficially owned approximately 57% of the Partnership’s total limited partner interest in the Partnership.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 conformityaccordance with GAAP. All material intercompany balances and transactions arehave been eliminated upon consolidation. We report our operations in consolidation.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 suchSEC rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Qreport should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2016,2022, 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 atas 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 theeach particular circumstances.circumstance. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests and unit–based compensation.

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, early application permitted for annual reporting period beginning after December 31, 2016. The standard allows for either full retrospective adoption, meaning

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


(Unaudited)

interests, estimates of third party operated royalty income related to expected sales volumes and prices, the standard is applied to all periods presented inrecoverability of costs of unevaluated properties, the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Partnership is currently evaluating the impact of this standard; however, the Partnership has reviewed its various contracts and has not identified any revenue that would be materially impacted and therefore does not expect the adoption of this standard to have a material impact on the Partnership’s financial position, results of operations and liquidity. The Partnership anticipates using the modified retrospective adoption.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. This update will be effective for public entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. Entities should apply the amendments by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The Partnership will be required to mark its cost method investment to fair value with the adoption of this update.

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Partnership believes the primary impact of adopting this standard will be the recognitiondetermination 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 balance sheetface of the condensed consolidated financial statements as of June 30, 2023 and for current operating leases. the three and six months ended June 30, 2023 and 2022.

Accrued Liabilities

Accrued liabilities consist of the following:

June 30,December 31,
20232022
(In thousands)
Interest payable$4,449 $3,972 
Ad valorem taxes payable9,963 12,492 
Derivatives instruments payable1,756 1,684 
Other1,959 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 is still evaluatingconsiders the applicability and impact of this standard.

In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-09, "Compensation - Stock Compensation". This update applies to all entitiesASUs. There are no recent accounting pronouncements not yet adopted that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update was effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Partnership prospectively adopted this standard effective January 1, 2017. The Partnership elected to account for forfeitures as they occur as a result of adopting this standard.

In April 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-10, “Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing”. This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is notare expected to have a material impacteffect on the Partnership's financial position, results of operations and liquidity.Partnership upon adoption, as applicable.

In May 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-12, “Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients”. This update applies only to the following areas from Accounting Standards Codification Topic 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Partnership


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


(Unaudited)

3.    REVENUE FROM CONTRACTS WITH CUSTOMERS
does not believe
Royalty income represents the adoptionright to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of this standard will havethe wells in which the Partnership owns a material impactroyalty 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 financial statements sincepercentage ownership share of the Partnership does not have a historyrevenue, net of credit losses.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. This update will be effectiveany deductions for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. This update will be applied retrospectively. The Partnership does not expect the adoption of this standard to have a material impact on the Partnership’s financial position, results of operationsgathering and liquidity.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantiallytransportation. Virtually all of the fairpricing 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,
2023202220232022
(In thousands)
Oil income$139,300 $191,195 $275,919 $346,246 
Natural gas income5,090 23,793 14,081 38,983 
Natural gas liquids income13,807 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 gross assets acquired (or disposed of) is concentratedproperties approximated the Drop Down purchase price.

Other Acquisitions

Additionally in a single identifiable asset or a groupthe first half of similar identifiable assets, the set is not a business. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years. This update should be applied prospectively on or after the effective date. This update is not expected to have a material impact on the Partnership’s financial statements or results of operations. The adoption of this update will change the process that the Partnership uses to evaluate whether the Partnership has acquired a business or an asset. This update will be applied prospectively and will not have an effect on prior acquisitions.

3.    ACQUISITIONS

During the nine months ended September 30, 2017,2023, the Partnership acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests underlying 2,769representing 203 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $304.6$48.1 million, and, as of September 30, 2017, had mineral interests underlying 9,173 net royalty acres.subject to customary post-closing adjustments. The Partnership funded these acquisitions primarily with cash on hand and borrowings under itsthe Operating Company’s revolving credit facility,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 a portioncash on hand and borrowings under the Operating Company’s revolving credit facility.

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

In the first quarter of 2022, the Partnership divested 325 net proceeds fromroyalty 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 January and July 2017 offeringsentire position in the Eagle Ford Shale consisting of common units and with the issuance681 net royalty acres of 174,513 common units to a seller in a private placement in May 2017.third party operated acreage for an aggregate net sales price of $53.7 million, including customary closing adjustments.


4.5.    OIL AND NATURAL GAS INTERESTS


Oil and natural gas interests include the following:
June 30,December 31,
20232022
(In thousands)
Oil and natural gas interests:
Subject to depletion$2,394,553 $2,167,598 
Not subject to depletion1,195,923 1,297,221 
Gross oil and natural gas interests3,590,476 3,464,819 
Accumulated depletion and impairment(785,286)(720,234)
Oil and natural gas interests, net2,805,190 2,744,585 
Land5,688 5,688 
Property, net of accumulated depletion and impairment$2,810,878 $2,750,273 
 September 30,December 31,
 20172016
   
 (in thousands)
Oil and natural gas interests:  
Subject to depletion$577,493
$508,586
Not subject to depletion487,899
252,232
Gross oil and natural gas interests1,065,392
760,818
Accumulated depletion and impairment(177,534)(148,948)
Oil and natural gas interests, net$887,858
$611,870
   
Balance of acquisition costs not subject to depletion  
Incurred in 2017$250,227
 
Incurred in 2016$162,984
 
Incurred in 2015$32,067
 
Incurred in 2014$42,621
 
Total not subject to depletion$487,899
 


Costs associated with unevaluated interests are excluded from the full cost pool until a determination as to the existenceAs of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within three to five years.


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Under the full cost method of accounting,June 30, 2023 and December 31, 2022, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling,had mineral and royalty interests representing 27,178 and 26,315 net royalty acres, respectively.

No impairment expense was recorded on the book value of the proved oil and gas interests. Net capitalized costs are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Partnership’s oil and natural gas revenue, (b)interests for the cost of interests not being amortized, if any,three and (c)six months ended June 30, 2023 and 2022 based on the lower of cost or market value of unproved interests included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write down is required.

As a resultresults of the decline in prices, the Partnership recorded a non-cash impairment for the nine months ended September 30, 2016 of $47.5 million, which is included in accumulated depletion and impairment. There was no impairment recorded for the nine months ended September 30, 2017. For 2016, the impairment charge affected the Partnership’s reported net loss but did not reduce its cash flow.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.


5.6.    DEBT


Credit Agreement-Wells Fargo BankLong-term debt consisted of the following as of the dates indicated:


June 30,December 31,
20232022
(In thousands)
5.375% senior unsecured notes due 2027$430,350 $430,350 
Revolving credit facility224,000 152,000 
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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Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The Partnership is partyOperating Company’s Revolving Credit Facility

On May 31, 2023, the Operating Company entered into a tenth amendment to a secured revolvingthe existing credit agreement, dated as of July 8, 2014, as amended, with Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement provides for a revolving credit facility inwhich 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 subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Partnership’s oil and natural gas reserves and other factors. $750.0 million. The borrowing base is scheduled to be re-determinedredetermined semi-annually with effective dates of April 1stin May and October 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period.November. As of SeptemberJune 30, 2017,2023, the borrowing base 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 set at $315.0 millionin 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 $35.5 million ina total of 71,206,622 common units issued and outstanding borrowings under its credit agreement.

Theand 90,709,946 Class B units issued and outstanding, borrowings under the credit agreement bear interest at a rate electedof which 731,500 common units and 90,709,946 Class B units were beneficially owned by the Partnership that is equal to an alternative base rate (which is equal to the greatestDiamondback, representing approximately 57% of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00%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 caseOperating 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 alternative base rate and from 2.00%Partnership’s General Partner has approved a common unit repurchase program to 3.00% in acquire up to $750.0 million of the casePartnership’s outstanding common units, excluding excise tax, over an indefinite period of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. time. The Partnership is obligatedintends to pay a quarterly commitment fee rangingpurchase common units under the repurchase program opportunistically with funds from 0.375% to 0.500% per yearcash on hand, free cash flow from operations and potential liquidity events such as the unused portionsale of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principalassets. This repurchase program may be optionally repaidsuspended from time to time, without premiummodified, extended or penalty (other than customary LIBOR breakage), and is required to be repaid (a) todiscontinued by the extent that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity dateboard of July 8, 2019. The loan is secured by substantially alldirectors of the assets of the Partnership and its subsidiary.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.

Financial CovenantRequired Ratio
Ratio of total debt to EBITDAXNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of any event of default. The Partnership’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There

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Viper Energy Partners LP
Notes to Financial Statements - (Continued)
(unaudited)



are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

6.    RELATED PARTY TRANSACTIONS

Partnership Agreement

In connection with the closing of the IPO, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For the three and nine months ended September 30, 2017, the General Partner allocated $0.6 million and $1.8 million, respectively, to the Partnership.at any time. During the three and ninesix months ended SeptemberJune 30, 2016, no expenses were allocated to2023 and 2022, the Partnership byrepurchased, excluding excise tax, approximately $24.3 million, $57.0 million, $28.9 million and $68.2 million of common units under the General Partner.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.


Advisory Services AgreementCash Distributions


In connectionEffective with the closing of the IPO, the Partnership and General Partner entered into an advisory services agreement with Wexford Capital LP (“Wexford”) dated as of June 23, 2014 (the “Advisory Services Agreement”), under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the Partnership’s business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement has an initial term of two years commencing on June 23, 2014, and continues for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. For the three and nine months ended September 30, 2017 and 2016, the Partnership did not pay any costs under the Advisory Services Agreement.

Tax Sharing

In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondbackdistribution payable for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period.

Lease Bonus

During the three months ended September 30, 2017, Diamondback did not pay the Partnership any lease bonus payments. During the nine months ended September 30, 2017, Diamondback paid the Partnership $0.1 million in lease bonus payments to extend the termthird quarter of two leases, reflecting an average bonus of $7,459 per acre. During the three months ended September 30, 2016, Diamondback paid the Partnership $5,000 in lease bonus payments to extend the term of two leases, reflecting an average bonus of $200 per acre. During the nine months ended September 30, 2016, Diamondback paid the Partnership $0.3 million, respectively, in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.
7.    UNIT-BASED COMPENSATION

In connection with the IPO,2022, the board of directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“LTIP”), effective June 17, 2014, for employees, officers, consultantsapproved a distribution policy consisting of a base and directorsvariable distribution, that takes into account capital returned to unitholders via our common unit repurchase program. For a detailed description of the General PartnerPartnership’s and any of its affiliates, including Diamondback, who perform servicesthe 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 Partnership. year ended December 31, 2022.

The LTIP providespercentage of cash available for distribution pursuant to the grantdistribution 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 options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards,repurchase program. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other unit-based awards and substitute awards. As of September 30, 2017, a total of 9,070,356 common unitsbasis.


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Condensed Notes to Consolidated Financial Statements - (Continued)
(unaudited)(Unaudited)



had been reserved for issuance pursuant to the LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the board of directors of the General Partner or a committee thereof.

For the three and nine months ended September 30, 2017, the Partnership incurred $0.5 million and $2.0 million of unit–based compensation.

Phantom Units

Under the LTIP, the board of directors of the General Partner is authorized to issue phantom units to eligible employees and non-employee directors. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient to one common unit of the Partnership for each phantom unit.

The following table presents the phantom unit activity under the LTIP for the nine months ended September 30, 2017:
 Phantom
Units		 Weighted Average
Grant-Date
Fair Value
Unvested at December 31, 201621,048
 $16.23
Granted103,190
 $16.79
Vested(32,176) $16.49
Unvested at September 30, 201792,062
 $16.77

The aggregate fair value of phantom units that vested during the nine months ended September 30, 2017 was $0.5 million. As of September 30, 2017, the unrecognized compensation cost related to unvested phantom units was $1.4 million. Such cost is expected to be recognized over a weighted-average period of 1.3 years.

8.    UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and common unit partnership interests. The general partner interest is a non-economic interest and is not entitled to any cash distributions.

At September 30, 2017, the Partnership had a total of 113,882,045 common units issued and outstanding, of which 73,150,000 common units were owned by Diamondback, representing approximately 64% of the total Partnership common units outstanding.

The following table summarizes changes in the number of the Partnership’s common units:
Common Units
Balance at December 31, 201687,800,356
Common units issued in public offerings25,875,000
Common units vested and issued under the LTIP32,176
Common units issued for acquisition174,513
Balance at September 30, 2017113,882,045

The board of directors of the General Partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis, beginning with the quarter ended September 30, 2014.


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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:presented (in thousands, except for per unit amounts):
PeriodAmount per Operating Company UnitOperating Company Distributions to DiamondbackAmount per Common Unit
Distributions to Common Unitholders(1)
Declaration DateUnitholder Record DatePayment Date
Q4 2022$0.54 $48,983 $0.49 $35,683 February 15, 2023March 3, 2023March 10, 2023
Q1 2023$0.42 $38,097 $0.33 $23,797 April 26, 2023May 11, 2023May 18, 2023
  Amount per Common Unit Declaration Date Unitholder Record Date Payment Date
Q4 2016 $0.258
 February 3, 2017 February 17, 2017 February 24, 2017
Q1 2017 $0.302
 April 28, 2017 May 18, 2017 May 25, 2017
Q2 2017 $0.332
 July 28, 2017 August 17, 2017 August 24, 2017
(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. Available cash for each quarter will be determined by

Change in Ownership of Consolidated Subsidiaries

Non-controlling interest in the board of directorsaccompanying condensed consolidated financial statements represents Diamondback’s ownership in the net assets of the General PartnerOperating 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 percentageresult in adjustments to non-controlling interest and common unitholder equity, tax effected, but do not impact earnings. The following table summarizes the end of such quarter. Available cash for each quarter will generally equal Adjusted EBITDA reduced for cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs thatchanges in common unitholder equity due to changes in ownership interest during the board of directors of the General Partner deems necessary or appropriate, if any.period:


Three Months Ended June 30,Six Months Ended June 30,
2023202220232022
(In thousands)
Net income (loss) attributable to the Partnership$30,550 $34,022 $64,517 $50,627 
Change in ownership of consolidated subsidiaries16,749 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 
9.
8.    EARNINGS PER COMMON UNIT


The net income (loss) per common unit on the condensed consolidated statements of operations is based on the net income (loss) of the Partnership for the three and nine months ended September 30, 2017 and 2016, since this is the amount of net income (loss) that is attributable to the Partnership’s common units.

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. Payments made

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 Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 8—Unitholders’ Equityrespective ownership among holders of common units and Partnership Distributions.

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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Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
 (In thousands, except per unit amounts)
Net income (loss) attributable to the period26,607
10,202
 69,408
(27,153)
Weighted average common units outstanding     
Basic weighted average common units outstanding110,377
84,996
 101,095
81,496
Effect of dilutive securities:     
Potential common units issuable47
7
 48
—
Diluted weighted average common units outstanding110,424
85,003
 101,143
81,496
Net income per common unit, basic$0.24$0.12 $0.69$(0.33)
Net income per common unit, diluted$0.24$0.12 $0.69$(0.33)
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,
2023202220232022
(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 outstanding71,771 76,620 72,249 76,861 
Effect of dilutive securities:
Potential common units issuable(2)
— 109 — 117 
Diluted weighted average common units outstanding71,771 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 SeptemberJune 30, 20172023 and 2016,2022, there were 1,356no potential common units and 1,514,069 common units, respectively, and for the nine months ended September 30, 2017 and 2016, there were 43,414 common units and 1,583,376 common units, respectively, that were not included inexcluded from the computation of diluted earnings per common unit because their inclusion would have been anti-dilutiveanti-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,
2023202220232022
(In thousands, except for tax rate)
Provision for (benefit from) income taxes$8,450 $6,182 $17,856 $8,812 
Effective tax rate9.6 %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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Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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.

SwapsPuts
Settlement MonthSettlement YearType of ContractBbls/Mcf Per DayIndexWeighted Average DifferentialStrike PriceDeferred Premium
OIL
Jul. - Sep.2023Puts12,000WTI Cushing$—$55.00$1.80
Oct. - Dec.2023Puts12,000WTI Cushing$—$55.00$1.85
Jul. - Dec.2023Basis Swaps4,000Argus WTI Midland$1.05$—$—
NATURAL GAS
Jul. - Dec.2023Basis Swaps30,000Waha Hub$(1.33)$—$—
Jan. - Dec.2024Basis Swaps30,000Waha 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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Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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,
2023202220232022
(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 but could potentially dilute basic earnings per common unit in future periods.the Partnership’s condensed consolidated balance sheets as of June 30, 2023 and December 31, 2022:


As of June 30, 2023
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet 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 $— $3,373 
10.
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Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
As of December 31, 2022
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In thousands)
Assets:
Current:
Derivative instruments$— $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, 2023December 31, 2022
Carrying ValueFair ValueCarrying ValueFair 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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Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
12.    COMMITMENTS AND CONTINGENCIES


The Partnership could be subjectis a party to various possibleroutine 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 contingencies which arise primarily from interpretationis probable and the amount of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales mayloss can be made, the prices at which royalty owners may be paid for productionreasonably estimated.


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from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

11.13.    SUBSEQUENT EVENTS


Cash Distribution


On October 16, 2017,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 thirdsecond quarter of 20172023 of $0.337$0.36 per common unit and $0.44 per Class B unit, payable on November 14, 2017,August 17, 2023, to eligible unitholders of record at the close of business on November 7, 2017.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, 2016.2022. 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 “PartPart II. Item 1A. Risk Factors”Factors and “CautionaryCautionary Statement Regarding Forward-Looking Statements.”Statements.


Overview


We are a publicly traded Delaware limited partnership formed by Diamondback on February 27, 2014 to among other things, own and acquire mineral and exploitroyalty interests in oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas propertiesprimarily in the Permian Basin. As of September 30, 2017, our general partner held a 100% non-economic general partner interest in us, and Diamondback had an approximate 64% limited partner interest in us. Diamondback also owns and controls our general partner.

In January 2017, we completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. We received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which $120.5 million was used to repay the outstanding borrowings under our revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.
In July 2017, we completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Diamondback purchased 700,000 common units, an affiliate of our general partner purchased 3,000,000 common units and certain officers and directors of Diamondback and our general partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, Diamondback had an approximate 64% limited partner interest in us. We received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which we used $152.8 million to repay all of the then-outstanding borrowings under our revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes, which included additional acquisitions.
We operate in one reportable segment engaged in the acquisition ofsegment. 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 properties. Our assets consistliquids are determined primarily of producing oilby prevailing market conditions. Regional and natural gas interests principally locatedworldwide economic activity, including any economic downturn or recession that has occurred or may occur in the Permian Basinfuture, 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 West Texas.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
Sources
On July 25, 2023, the board of Our Incomedirectors 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.


Our incomeIntent 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 derived from royalty paymentsexpected 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 receive fromintend to adopt a corporate governance structure designed to meet the eligibility requirements for certain indices and benchmarks, which we believe would further broaden our operators based on the sale of oilinvestor base and natural gas production, as well as the sale of natural gas liquids thatimprove our trading liquidity, although no assurances can be provided regarding inclusion in any such index or benchmark. Because we are extracted from natural gas during processing. Royalty payments may vary significantly from period to periodalready treated as a resultcorporation for U.S. federal income tax purposes, we expect that the conversion of commodity prices, production mixour 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 volumesadministrative 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 production sold by our operators.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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The following table presents the breakdown of our royalty income for the following periods:
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
Royalty income     
Oil sales85%90% 88%91%
Natural gas sales7%4% 6%4%
Natural gas liquid sales8%6% 6%5%
 100%100% 100%100%

As a result, our income is more sensitive to fluctuations in oil prices than is it to fluctuations in natural gas liquids or natural gas prices. Our income may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile.

During 2016, West Texas Intermediate posted prices ranged from $26.19 to $54.01 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. During the first nine months of 2017, West Texas Intermediate posted prices ranged from $42.48 to $54.48 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On September 29, 2017, the West Texas Intermediate posted price for crude oil was $51.67 per Bbl and the Henry Hub spot market price of natural gas was $2.94 per MMBtu. Lower prices may not only decrease our income, but also potentially the amount of oil and natural gas that our operators can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be redetermined at the discretion of our lenders.

Recent Acquisitions

During the third quarter of 2017, we acquired 1,677 net royalty acres for an aggregate purchase price of $178.9 million, subject to post-closing adjustments, bringing our total mineral interests to 9,173 net royalty acres as of September 30, 2017.

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 dailyoil production per day during the thirdsecond quarter of 20172023 was 12,611 BOE/d (68% oil), and our operators received an average of $45.33 per Bbl of oil, $19.10 per Bbl of natural gas liquids and $2.55 per Mcf of natural gas, for an average realized price of $36.38 per BOE.

During the third quarter of 2017,highest in the operators of our Spanish Trail mineral interests brought online nine gross horizontal wells with an average royalty interest of 12.2%, consisting of three Lower Spraberry, four Wolfcamp A, one Wolfcamp B and one Middle Spraberry wells. As of September 30, 2017, there were approximately 24 horizontal wells with an average royalty interest of 21.2% in various stages of drilling or completion on this acreage. Additionally, there is active development activityPartnership’s history. There are currently 47 rigs operating on our mineral and royalty acreage, outsideeight of Spanish Trail in Loving, Reeves, Midland, Pecos, Ward, Martin, Howard and Glasscock counties.  As of September 30, 2017, we had 736 vertical wells and 478 horizontal wells producing on our acreage. As of October 20, 2017, there were 22 active rigs and 319 active horizontal drilling permits on our acreage. We intend to continue to be active in acquiring mineral interests with near term visibility and accretive cash flow growth.

We declared a cash dividend for the third quarter of 2017 of $0.337 per common unit, payable on November 14, 2017, to unitholders of record at the close of business on November 7, 2017.

Principal Components of Our Cost Structure

Production and Ad Valorem Taxes

Production taxeswhich are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates establishedoperated by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas interests.


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General and Administrative

In connection with the closing of the IPO, our general partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated as of June 23, 2014. The partnership agreement requires us to reimburse our general partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. The partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

In connection with the closing of the IPO, we and our general partner entered into an advisory services agreement with Wexford, pursuant to which Wexford provides general financial and strategic advisory services to us and our general partner in exchange for a $0.5 million annual fee and certain expense reimbursement.

Depreciation, Depletion and Amortization

Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved interests and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization.

Income Tax Expense

We are organized as a pass-through entity for income tax purposes.Diamondback. As a result our partners are responsible for federal income taxes on their shareof the continued outperformance of our taxable income.

We are subjectproduction 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 Texas margin tax. Diamondback does notsecond quarter of 2023. Due to Diamondback’s consistent focus on developing our high concentration royalty acreage, primarily in the Northern Midland Basin, we expect any Texas margin taxour Diamondback-operated full year 2023 oil production to be dueincrease by over 15% compared to 2022, with a further increase of approximately 10% expected for the nine months ended September 30, 2017 or 2016.full year 2024.


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Results of Operations


The following table summarizes our revenue and expenses and production datagross well information for the periods indicated.second quarter ended June 30, 2023:

Diamondback OperatedThird Party OperatedTotal
Horizontal wells turned to production(1):
Gross wells81204285
Net 100% royalty interest wells3.92.05.9
Average percent net royalty interest4.8 %1.0 %2.1 %
Horizontal producing well count:
Gross wells1,6534,1895,842
Net 100% royalty interest wells120.868.1188.9
Average percent net royalty interest7.3 %1.6 %3.2 %
Horizontal active development well count(2):
Gross wells110353463
Net 100% royalty interest wells6.52.99.4
Average percent net royalty interest5.9 %0.8 %2.0 %
Line of sight wells(3):
Gross wells206371577
Net 100% royalty interest wells12.35.617.9
Average percent net royalty interest6.0 %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.

18
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
 (unaudited, in thousands, except production data)
Operating Results:     
Operating income:     
Royalty income$42,211
$19,992
 $110,194
$50,914
Lease bonus322
5
 2,613
309
Total operating income42,533
19,997
 112,807
51,223
Costs and expenses:     
Production and ad valorem taxes2,825
1,429
 7,668
4,134
Gathering and transportation205
70
 492
247
Depletion11,068
6,751
 28,587
21,485
Impairment—
—
 —
47,469
General and administrative expenses1,368
1,153
 5,064
4,109
Total costs and expenses15,466
9,403
 41,811
77,444
Income (loss) from operations27,067
10,594
 70,996
(26,221)
Other income (expense):     
Interest expense(859)(658) (2,114)(1,544)
Other income399
266
 526
612
Total other income (expense), net(460)(392) (1,588)(932)
Net income (loss)$26,607
$10,202
 $69,408
$(27,153)
      
Production Data:     
Oil (Bbls)794,375
430,732
 2,077,570
1,236,003
Natural gas (Mcf)1,236,349
315,030
 2,460,535
1,008,745
Natural gas liquids (Bbls)159,806
92,221
 393,913
221,582
Combined volumes (BOE)1,160,239
575,458
 2,881,572
1,625,709
Daily combined volumes (BOE/d)12,611
6,255
 10,555
5,933
% Oil68%75% 72%76%
      
Average sales prices:     
Oil, realized ($/Bbl)$45.33
$41.97
 $46.51
$37.64
Natural gas realized ($/Mcf)2.55
2.39
 2.62
1.89
Natural gas liquids ($/Bbl)19.10
12.56
 18.07
11.25
Average price realized ($/BOE)36.38
34.74
 38.24
31.32
      
Average Costs ($/BOE)     
Production and ad valorem taxes$2.43
$2.48
 $2.66
$2.54
Gathering and transportation expense0.18
0.12
 0.17
0.15
General and administrative - cash component0.75
0.19
 1.05
0.70
Total operating expense - cash$3.36
$2.79
 $3.88
$3.39
      
General and administrative - non-cash component$0.43
$1.81
 $0.71
$1.83
Interest expense0.74
1.14
 0.73
0.95
Depletion9.54
11.73
 9.92
13.22


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Comparison of the Three Months Ended SeptemberJune 30, 20172023 and 2016March 31, 2023


Results of Operations

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

Three Months Ended
June 30, 2023March 31, 2023
 (In thousands)
Operating income:
Oil income$139,300 $136,619 
Natural gas income5,090 8,991 
Natural gas liquids income13,807 15,475 
Royalty income158,197 161,085 
Lease bonus income—related party1,277 7,071 
Lease bonus income1,134 400 
Other operating income179 402 
Total operating income160,787 168,958 
Costs and expenses:
Production and ad valorem taxes12,621 12,887 
Depletion34,064 30,987 
General and administrative expenses2,008 2,764 
Total costs and expenses48,693 46,638 
Income (loss) from operations112,094 122,320 
Other income (expense):
Interest expense, net(11,291)(9,686)
Gain (loss) on derivative instruments, net(12,594)(15,103)
Other income, net172 141 
Total other expense, net(23,713)(24,648)
Income (loss) before income taxes88,381 97,672 
Provision for (benefit from) income taxes8,450 9,406 
Net income (loss)79,931 88,266 
Net income (loss) attributable to non-controlling interest49,381 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, 2023March 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 for the three months ended September 30, 2017 and 2016 was $42.2 million and $20.0 million, respectively. Our royalty income is a function of oil, natural gas liquids and natural gas liquids production volumes sold and average prices received for those volumes.


In addition to the increase in average prices receivedRoyalty income decreased $2.9 million during the three months ended September 30, 2017, we also benefited from a 101.6% increase in combined volumes sold by our operators assecond quarter of 2023 compared to the three months ended September 30, 2016.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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 Change in prices
Production volumes(1)
Total net dollar effect of change
   (in thousands)
Effect of changes in price:   
Oil$3.36
794,375
$2,669
Natural gas liquids6.54
159,806
1,045
Natural gas0.16
1,236,349
198
Total income due to change in price  $3,912
    
 
Change in production volumes(1)
Prior period average pricesTotal net dollar effect of change
   (in thousands)
Effect of changes in production volumes:   
Oil363,643
$41.97
$15,256
Natural gas liquids67,585
12.56
849
Natural gas921,319
2.39
2,202
Total income due to change in production volumes  18,307
Total change in income  $22,219
(1)Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas.

Lease Bonus IncomeIncome-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, 2023March 31, 2023
Amount
(In thousands)		Per BOEPercentage of Royalty IncomeAmount
(In thousands)		Per BOEPercentage of Royalty Income
Production taxes$7,807 $2.28 5.0 %$8,177 $2.60 5.1 %
Ad valorem taxes4,814 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 by $0.3 millionslightly 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, 2023March 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 SeptemberJune 30, 20172023 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 three months ended September 30, 2016. During the three months ended September 30, 2017, we received $0.3 million in lease bonus payments to extend the termfirst quarter of one lease, reflecting an average bonus of $10,000 per acre.

General and Administrative Expenses

The general and administrative expenses primarily reflect costs associated with us being a publicly traded limited partnership, unit-based compensation and the amounts reimbursed to our general partner under our partnership agreement. For the three months ended September 30, 2017 and 2016, we incurred general and administrative expenses of $1.4 million and $1.2 million, respectively. The increase of $0.2 million during the three months ended September 30, 2017 was2023 is primarily due to the reimbursement of expensesdecrease in pre-tax income attributable to the General Partner underPartnership. See Note 9—Income Taxes of the Partnership Agreement, partially offset by a decrease in unit-based compensation expense.notes to the condensed consolidated financial statements for further details.


Net Interest Expense
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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,
20232022
 
Operating income:
Oil income$275,919 $346,246 
Natural gas income14,081 38,983 
Natural gas liquids income29,282 46,690 
Royalty income319,282 431,919 
Lease bonus income—related party8,348 6,280 
Lease bonus income1,534 2,731 
Other operating income581 295 
Total operating income329,745 441,225 
Costs and expenses:
Production and ad valorem taxes25,508 29,909 
Depletion65,051 59,373 
General and administrative expenses4,772 3,833 
Total costs and expenses95,331 93,115 
Income (loss) from operations234,414 348,110 
Other income (expense):
Interest expense, net(20,977)(19,427)
Gain (loss) on derivative instruments, net(27,697)(20,248)
Other income, net313 38 
Total other expense, net(48,361)(39,637)
Income (loss) before income taxes186,053 308,473 
Provision for (benefit from) income taxes17,856 8,812 
Net income (loss)168,197 299,661 
Net income (loss) attributable to non-controlling interest103,680 249,034 
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,
20232022
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 interestof 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 three months ended September 30, 2017 and 2016 reflects the interest incurred under our credit agreement. Net interest expense for the three months ended September 30, 2017 and 2016 was $0.9 million and $0.7 million, respectively. The increase of $0.2 million was due to a higher interest rate and increased borrowings during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016.respective periods presented.


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Comparison of the Nine Months Ended September 30, 2017 and 2016


Royalty Income


Our royalty income for the nine months ended September 30, 2017 and 2016 was $110.2 million and $50.9 million, respectively. Our royalty income is a function of oil, natural gas liquids and natural gas liquids production volumes sold and average prices received for those volumes.


Royalty income 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,
20232022
Amount
(In thousands)		Per BOEPercentage of Royalty IncomeAmount
(In thousands)		Per BOEPercentage of Royalty Income
Production taxes$15,984 $2.43 5.0 %$21,894 $3.71 5.1 %
Ad valorem taxes9,524 1.453.0 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 additiongeneral, 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,
20232022
(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 average prices received during the nine months ended September 30, 2017, we also benefited from a 77.3% increase in combined volumes sold by our operators as comparedpre-tax income attributable to the nine months ended September 30, 2016.

 Change in prices
Production volumes(1)
Total net dollar effect of change
   (in thousands)
Effect of changes in price:   
Oil$8.87
2,077,570
$18,433
Natural gas liquids6.82
393,913
2,686
Natural gas0.73
2,460,535
1,796
Total income due to change in price  $22,915
    
 
Change in production volumes(1)
Prior period average pricesTotal net dollar effect of change
   (in thousands)
Effect of changes in production volumes:   
Oil841,567
$37.64
$31,682
Natural gas liquids172,331
11.25
1,939
Natural gas1,451,790
1.89
2,744
Total income due to change in production volumes  36,365
Total change in income  $59,280
(1)Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas.

Lease Bonus Income

Lease bonus income increased by $2.3 million for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016. During the nine months ended September 30, 2017, we received $2.6 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $3,333 per acre.

Impairment of Oil and Gas Properties

During the nine months ended September 30, 2016, we recorded an impairment of oil and gas properties of $47.5 millionPartnership as a result of the significant declineexpiration 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 commodity prices. No impairment was recordednet income (loss) attributable to non-controlling interest for the ninesix months ended SeptemberJune 30, 2017.

General and Administrative Expenses

For2023 compared to the nine months ended September 30, 2017 and 2016, we incurred general and administrative expenses of $5.1 million and $4.1 million, respectively. The increase of $1.0 million during the nine months ended September 30, 2017 wassame period in 2022 is primarily due to the reimbursementexpiration of expenses to the General Partner under the Partnership Agreement, partially offset by a decrease in unit-based compensation expense.special income allocation at December 31, 2022.



17
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Net Interest Expense

The net interest expense for the nine months ended September 30, 2017 and 2016 reflects the interest incurred under our credit agreement. Net interest expense for the nine months ended September 30, 2017 and 2016 was $2.1 million and $1.5 million, respectively. The increase of $0.6 million was due to a higher interest rate and increased borrowings during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016.

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.

We define Adjusted EBITDA as net income (loss) plus interest expense, non-cash unit-based compensation expense, depletion expense and impairment expense. Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, royalty income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA to net income, our most directly comparable GAAP financial measure for the periods indicated.
 Three Months Ended September 30, Nine Months Ended September 30,
 20172016 20172016
 (In thousands)
Net income (loss)$26,607
$10,202
 $69,408
$(27,153)
Interest expense859
658
 2,114
1,544
Non-cash unit-based compensation expense503
1,044
 2,039
2,974
Depletion11,068
6,751
 28,587
21,485
Impairment—
—
 —
47,469
Adjusted EBITDA$39,037
$18,655
 $102,148
$46,319

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 ourthe Operating Company’s credit agreement, and ouragreement. Our primary uses of cash have been and are expected to continue to be, distributions to our unitholders, and replacement and growthrepayments of debt, capital expenditures includingfor the acquisition of our mineral and royalty interests in oil and natural gas interests.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 intendmay draw on the Operating Company’s credit agreement to finance potential future acquisitions through a combination ofmeet short-term cash on hand, borrowings under our credit agreement and, subject to market conditions and other factors, proceeds from onerequirements, or more capital market transactions, which may includeissue debt or equity offerings. Our ability to generate cash is subject to a numbersecurities as part of factors, some of which are beyond our control, including commodity priceslonger-term liquidity and general economic, financial, competitive, legislative, regulatory and other factors, including weather.

Our partnership agreement does not require us to distribute anycapital management program. Because of the cashalternatives available to us as discussed above, we generate from operations. We believe however, that it is in the bestour 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 our unitholders if we distribute a substantial portion of the cash we generate from operations. The board of directors of our general partner has adopted a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders.

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On October 16, 2017, the board of directors of the General Partner approved a cash distribution for the third quarter of 2017 of $0.337 perdebt maturities, common unit payable on November 14, 2017, to unitholders of record at the close of business on November 7, 2017.

Cash distributions are made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for each quarter generally equals Adjusted EBITDA reduced for cash needed for debt service and other contractual obligationssenior note repurchases and fixed charges and reserves for future operating or capital needsany amounts that the board of directors of our general partner deems necessary or appropriate, if any.

January 2017 Public Offering

In January 2017, we completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. We received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which $120.5 million was used to repay the outstanding borrowings under our revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.
July 2017 Public Offering
In July 2017, we completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. We received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commission and estimated offering expenses, of which $152.8 million was used to repay all of the then-outstanding borrowings under our revolving credit facility, and the balance was used to fund a portion of the purchase price for acquisitions and for general corporate purposes, which included additional acquisitions.
Our Credit Agreement

We are party to a $500.0 million secured revolving credit agreement, dated as of July 8, 2014, as amended, with Wells Fargo as the administrative agent, sole book runner and lead arranger, and certain other lenders party thereto. The credit agreement matures on July 8, 2019. As of September 30, 2017, the borrowing base was set at $315.0 million and we had $35.5 million in outstanding borrowings under our credit agreement.

The outstanding borrowings under the credit agreement bear interest at a rate elected by us that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may ultimately be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of our assets and our subsidiaries’ assets.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial CovenantRequired Ratio
Ratio of total debt to EBITDAXNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250.0 million in the form of senior unsecured notes and,paid in connection with any such issuance,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 reduction of the borrowing base by 25% of the

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stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under thecapital, financial and/or credit agreement upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of defaultmarkets due to non-paymentthe 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, principalcapital 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 breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.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 period indicated.periods indicated:

 Nine Months Ended September 30,
 20172016
   
 (in thousands)
Cash Flow Data:  
Net cash flows provided by operating activities$94,057
$46,554
Net cash flows used in investing activities(301,133)(137,786)
Net cash flows provided by financing activities202,301
98,451
Net increase (decrease) in cash$(4,775)$7,219
Six Months Ended June 30,
20232022
(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 volumevolumes of oil and natural gas sold by our producers. PricesThe 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 these commodities are determined primarily by prevailing market conditions. Regionalderivative settlements, and worldwide economic activity, weather(iii) a reduction in production and other substantially variable factors influence market conditionsad valorem taxes due to the corresponding decrease in royalty income. See “—Results of Operations” for these products. These factors are beyonddiscussion of significant changes in our controlrevenues and are difficult to predict.expenses.


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Investing Activities


Net cash used in investing activities was $301.1 million and $137.8 million during the ninesix months ended SeptemberJune 30, 2017 and 2016, respectively, and2023 primarily related to acquisitionsthe acquisition of mineral interests.oil and natural gas interests in the Drop Down and from other third-party acquisitions.

Financing Activities


Net cash provided by financingin investing activities was $202.3 million during the ninesix months ended SeptemberJune 30, 2017,2022 primarily related to net proceeds from the divestiture of $380.0oil 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 from our public offeringsand $57.5 million of common units,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 repayment of $85.0 million net of borrowings under ourOperating Company’s revolving credit agreement andfacility.

Net cash used in financing activities during the six months ended June 30, 2022, was primarily related to distributions of $92.5$194.1 million to our unitholders during the period. Net cash provided by financing activities was $98.5 million during the nine months ended September 30, 2016, primarily related to $20.0and $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 borrowingsrepayments of $54.0 million under ourthe 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 net proceedslong-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 $125.1availability 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 fromof our public offering of common units, partially offset by $46.7excluding 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 distributions to our unitholders during that period.the outstanding Notes in open market purchases or in privately negotiated transactions.


Cash Distributions
Contractual Obligations

There were no material changes in our contractual obligations and other commitments as disclosed in our Annual Report on Form 10-KThe distribution for the year ended December 31, 2016.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 PoliciesEstimates


There have been no changes to our critical accounting policiesestimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

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 pricing isprices are driven primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to ourfor natural gas production.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 particularly duringand the past two years, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.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 severala limited number of significant purchasers. For the nine months ended September 30, 2017, two purchasers each accounted for more than 10% of our royalty income: Shell Trading (US) Company (48%) and RSP Permian LLC (23%). For the nine months ended September 30, 2016, two purchasers each accounted for more than 10% of our royalty income: Shell Trading (US) Company (63%) and RSP Permian LLC (28%).producers. We do not require collateral and do not believe the lossfailure or inability of any singleour 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 would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.credit risk.


Interest Rate Risk


We are subject to market risk exposure related to changes in interest rates on our indebtedness under ourthe Operating Company’s credit agreement. The terms of ourthe 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 alternativealternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 3-month LIBOR1-month Adjusted Term SOFR plus 1.0%1.00%) or LIBOR,, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternative base rate and from 2.00% to 3.00% per annum in the case of LIBOR,Adjusted Term SOFR, in each case depending on the amount of the loanloans 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 entered into this credit agreementare obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on July 8, 2014, as subsequently amended, and asthe unused portion of Septemberthe commitment. As of June 30, 2017,2023, we had $35.5$224.0 million in outstanding borrowings. OurDuring the three and six months ended June 30, 2023, the weighted average interest rate on borrowings under ourthe Operating Company’s revolving credit facility was 3.24%7.53% and 7.24%. An increase or decrease

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Table of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $0.4 million based on the $35.5 million outstanding in the aggregate under our credit agreement.Contents


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,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,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 SeptemberJune 30, 2017,2023, 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,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 partnerGeneral Partner have concluded that as of SeptemberJune 30, 2017,2023, our disclosure controls and procedures are effective.



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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 SeptemberJune 30, 20172023 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.


In additionAs of the date of this filing, we continue to the information set forth in this report, you should carefully considerbe subject to the risk factors discussedpreviously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10–K10-K for the year ended December 31, 20162022, 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–K10-K for the year ended December 31, 2016.2022.


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:

PeriodTotal 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, 2023102,000$29.27 102,000$493,700 
May 1, 2023 - May 31, 2023379,500$26.91 379,500$483,487 
June 1, 2023 - June 30, 2023430,500$25.71 430,500$472,420 
Total912,000$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 NumberDescription
3.12.1
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(incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-195769) filed on May 7, 2014).
3.2
FirstSecond Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, (Incorporateddated as of May 9, 2018 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on June 23, 2014)May 15, 2018).
4.13.3
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 June 23, 2014,as of May 9, 2018, by and between Viper Energy Partners LP and Diamondback Energy, Inc. (Incorporated(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 23, 2014)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.INS*101XBRL Instance Document.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.
101.SCH*XBRL Taxonomy Extension Schema Document.
101.CAL*XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document.
*Filed herewith.
104Cover 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, 2023VIPER ENERGY PARTNERS LP
By:
By:VIPER ENERGY PARTNERS GP LLC
its General Partner
Date:October 25, 2017By:/s/ Travis D. Stice
Travis D. Stice
Chief Executive Officer
Date:October 25, 2017August 3, 2023By:/s/ Teresa L. Dick
Teresa L. Dick
Chief Financial Officer




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