UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

~~FOR THE QUARTERLY PERIOD ENDED~~ For the Quarterly Period Ended June 30, ~~2019~~2020



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

Commission File Number 001-36505

Viper Energy Partners LP

(Exact Name of Registrant As Specified in Its Charter)

46-5001985

(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification Number)

~~46-5001985~~

~~(State or Other Jurisdiction of Incorporation or Organization)~~

~~(I.R.S. Employer Identification Number)~~

500 West Texas

Suite 1200

Midland,

79701

(Address of principal executive offices)

(Zip code)

(~~432~~) (432) 221-7400

(Registrant's telephone number, including area code)

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units	VNOM	The Nasdaq Stock Market LLC
		(NASDAQ Global Select Market)

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

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

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

Large Accelerated Filer

☒

Accelerated Filer

☐

~~Large Accelerated Filer~~

☒

~~Accelerated Filer~~

☐

Non-Accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

As of July ~~26, 2019,~~31, 2020, the registrant had outstanding ~~62,631,420~~67,844,370 common units representing limited partner interests and ~~72,418,500~~90,709,946 Class B units representing limited partner ~~units.~~interests.

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VIPER ENERGY PARTNERS LP

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, ~~2019~~2020

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and gas terms that are used in this Quarterly Report on Form 10-Q (this “report”):



Basin			A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel			~~Stock~~One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
~~BOE~~			~~Barrels~~
BOE			One barrel of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d			BOE per day.
British Thermal Unit or Btu			The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
~~Condensate~~
Condensate			Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Crude oil			Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
~~Fracturing~~












Fracturing			The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.


Horizontal wells			Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.

MBbls			Thousand barrels of crude oil or other liquid hydrocarbons.
MBOE			One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf			~~Thousand~~One thousand cubic feet of natural gas.

Mineral interests			The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu			~~Million~~One million British Thermal Units.





Net royalty acres			Gross acreage multiplied by the average royalty interest.
Oil and natural gas properties			Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator			The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
~~Prospect~~




Prospect			A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved reserves			The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
~~Reserves~~

Reserves			The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir			A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty interest			An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of ~~development.~~development, which may be subject to expiration.
~~WTI~~





WTI			West Texas Intermediate.

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GLOSSARY OF CERTAIN OTHER TERMS

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



Diamondback			Diamondback Energy, Inc., a Delaware corporation.
Exchange Act			The Securities Exchange Act of 1934, as amended.
GAAP			Accounting principles generally accepted in the United States.
General Partner			Viper Energy Partners GP LLC, a Delaware limited liability company, and the General Partner of the Partnership.

IPO			The Partnership’s initial public offering.
LTIP			Viper Energy Partners LP Long Term Incentive Plan.
NYMEX			New York Mercantile Exchange.
Operating Company			Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy Partners LP.
Partnership			Viper Energy Partners LP, a Delaware limited partnership.
Partnership agreement			The first amended and restated agreement of limited partnership, dated June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the IPO.

SEC			United States Securities and Exchange Commission.
Securities Act			The Securities Act of 1933, as amended.
Wells Fargo			Wells Fargo Bank, National Association.

iii

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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 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 of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions 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 those detailed underPart II. Item 1A. Risk Factors in this report, our Annual Report on Form 10-K for the year ended December 31, 2019 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, 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 its consolidated subsidiary, Viper Energy Partners LLC (the “Operating Company”).

Forward-looking statements may include statements about:

~~our ability to execute our business strategies;~~

•the volatility of realized oil and natural gas ~~prices;~~prices and the extent and duration of price reductions and increased production by the Organization of the Petroleum Exporting Countries, or OPEC, members and other oil exporting nations;

•the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the recent outbreak of a highly transmissible and pathogenic strain of coronavirus, or COVID-19, or any government responses to such occurrence or threat;

•logistical challenges and the supply chain disruptions during the ongoing COVID-19 pandemic;

•changes in general economic, business or industry conditions;

•conditions in the capital, financial and credit markets;

•conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;

•U.S. and global economic conditions and political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental policies;

•our ability to execute our business and financial strategies;

•the level of production on our properties;

•regional supply and demand factors, delays, curtailments or interruptions of ~~production;~~production, and any government order, rule or regulation that may impose production limits on properties in which we have mineral and royalty interest;

•actions taken by third party operators on our mineral and royalty acreage;

•our ability to replace our oil and natural gas reserves;

•our ability to identify, complete and effectively integrate acquisitions of properties or ~~businesses, including our pending drop-down described in this report and our other recent and pending acquisitions;~~businesses;

~~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, pipeline and storage 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;

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•future operating results;

•future distributions to eligible unitholders;

•impact of potential impairment charges;

•exploration and development drilling prospects, inventories, projects and programs;

•operating hazards faced by our operators; ~~and~~

•the ability of our operators to keep pace with technological ~~advancements.~~advancements;

•the effect of existing and future laws and government regulations;

•terrorist attacks and cyber threats;

•the effects of future litigation; and

•certain other factors discussed elsewhere 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.

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PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Viper Energy Partners LP

Consolidated Balance Sheets

(Unaudited)


	June 30,		December 31,
	2020		2019
	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	9,663	$	3,602

Royalty income receivable (net of allowance for credit losses)	32,118		58,089
Royalty income receivable—related party	917		10,576

Other current assets	482		397
Total current assets	43,180		72,664
Property:
Oil and natural gas interests, full cost method of accounting ($1,480,346 and $1,551,767 excluded from depletion at June 30, 2020 and December 31, 2019, respectively)	2,933,731		2,868,459
Land	5,688		5,688
Accumulated depletion and impairment	(373,898)		(326,474)
Property, net	2,565,521		2,547,673


Deferred tax asset (net of allowance)	—		142,466
Other assets	15,572		22,823
Total assets	$	2,624,273	$	2,785,626
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	11	$	—
Accounts payable—related party	—		150
Accrued liabilities	12,439		13,282
Derivative instruments	33,956		—
Total current liabilities	46,406		13,432
Long-term debt, net	630,507		586,774

Derivative instruments	5,875		—
Total liabilities	682,788		600,206
Commitments and contingencies (Note 12)

Unitholders’ equity:
General partner	849		889
Common units (67,831,342 units issued and outstanding as of June 30, 2020 and 67,805,707 units issued and outstanding as of December 31, 2019)	728,149		929,116
Class B units (90,709,946 units issued and outstanding as of June 30, 2020 and December 31, 2019)	1,080		1,130
Total Viper Energy Partners LP unitholders’ equity	730,078		931,135
Non-controlling interest	1,211,407		1,254,285
Total equity	1,941,485		2,185,420
Total liabilities and unitholders’ equity	$	2,624,273	$	2,785,626

June 30, December 31,
2019 2018

(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents $ 12,804
$ 22,676
Royalty income receivable 46,819
38,823
Royalty income receivable—related party 9,038
3,489
Other current assets 211
257
Total current assets 68,872
65,245
Property:
Oil and natural gas interests, full cost method of accounting ($932,938 and $871,485 excluded from depletion at June 30, 2019 and December 31, 2018, respectively) 1,842,031
1,716,713
Land 5,688
5,688
Accumulated depletion and impairment (281,007 ) (248,296 )
Property, net 1,566,712
1,474,105
Funds held in escrow 13,215
—
Other assets 21,290
17,831
Deferred tax asset 150,344
96,883
Total assets $ 1,820,433
$ 1,654,064
Liabilities and Unitholders’ Equity
Current liabilities:
Other accrued liabilities $ 3,892
$ 6,022
Total current liabilities 3,892
6,022
Long-term debt 212,500
411,000
Total liabilities 216,392
417,022
Commitments and contingencies (Note 13)

Unitholders’ equity:
General partner 1,000
1,000
Common units (62,628,357 units issued and outstanding as of June 30, 2019 and 51,653,956 units issued and outstanding as of December 31, 2018) 795,903
540,112
Class B units (72,418,500 units issued and outstanding as of June 30, 2019 and December 31, 2018) 990
990
Total Viper Energy Partners LP unitholders’ equity 797,893
542,102
Non-controlling interest 806,148
694,940
Total equity 1,604,041
1,237,042
Total liabilities and unitholders’ equity $ 1,820,433
$ 1,654,064

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Operations

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(In thousands, except per unit amounts)
Operating income:
Royalty income	$	32,444	$	70,442	$	109,273	$	130,870
Lease bonus income	23		1,749		1,645		2,909

Other operating income	202		3		443		5
Total operating income	32,669		72,194		111,361		133,784
Costs and expenses:
Production and ad valorem taxes	3,110		4,389		9,257		8,081

Depletion	22,782		16,512		47,424		32,711

General and administrative expenses	1,683		1,723		4,349		3,418

Total costs and expenses	27,575		22,624		61,030		44,210
Income from operations	5,094		49,570		50,331		89,574
Other income (expense):
Interest expense, net	(7,669)		(2,713)		(16,632)		(7,262)


Loss on derivative instruments, net	(34,443)		—		(42,385)		—
Gain (loss) on revaluation of investment	3,443		50		(6,677)		3,642
Other income, net	519		547		923		1,203
Total other expense, net	(38,150)		(2,116)		(64,771)		(2,417)
(Loss) income before income taxes	(33,056)		47,454		(14,440)		87,157
Provision for (benefit from) income taxes	—		180		142,466		(34,428)
Net (loss) income	(33,056)		47,274		(156,906)		121,585
Net (loss) income attributable to non-controlling interest	(11,304)		45,009		7,015		85,541
Net (loss) income attributable to Viper Energy Partners LP	$	(21,752)	$	2,265	$	(163,921)	$	36,044

Net (loss) income attributable to common limited partner units:
Basic	$	(0.32)	$	0.04	$	(2.42)	$	0.61
Diluted	$	(0.32)	$	0.04	$	(2.42)	$	0.61
Weighted average number of common limited partner units outstanding:
Basic	67,831		62,628		67,827		59,058
Diluted	67,831		62,664		67,827		59,094

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 2019 2018
(In thousands, except per unit amounts)
Operating income:
Royalty income $ 70,442
$ 74,277
$ 130,870
$ 136,405
Lease bonus income 1,749
928
2,909
928
Other operating income 3
58
5
108
Total operating income 72,194
75,263
133,784
137,441
Costs and expenses:
Production and ad valorem taxes 4,389
4,867
8,081
9,106
Depletion 16,512
13,260
32,711
24,785
General and administrative expenses 1,723
2,210
3,418
4,921
Total costs and expenses 22,624
20,337
44,210
38,812
Income from operations 49,570
54,926
89,574
98,629
Other income (expense):
Interest expense, net (2,713 ) (3,252 ) (7,262 ) (5,350 )
Gain on revaluation of investment 50
4,465
3,642
5,364
Other income, net 547
447
1,203
839
Total other income (expense), net (2,116 ) 1,660
(2,417 ) 853
Income before income taxes 47,454
56,586
87,157
99,482
Provision for (benefit from) income taxes 180
(71,878 ) (34,428 ) (71,878 )
Net income 47,274
128,464
121,585
171,360
Net income attributable to non-controlling interest 45,009
29,060
85,541
29,060
Net income attributable to Viper Energy Partners LP $ 2,265
$ 99,404
$ 36,044
$ 142,300

Net income attributable to common limited partners per unit:
Basic $ 0.04
$ 1.36
$ 0.61
$ 1.52
Diluted $ 0.04
$ 1.35
$ 0.61
$ 1.52
Weighted average number of common limited partner units outstanding:
Basic 62,628
73,336
59,058
93,506
Diluted 62,664
73,427
59,094
93,612

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Changes to Unitholders' Equity

(Unaudited)


	Limited Partners												General Partner		Non-Controlling Interest
	Common			Class B			Amount		Amount
	Units	Amount		Units	Amount									Total
	(In thousands)
Balance at December 31, 2019	67,806	$	929,116	90,710	$	1,130	$	889	$	1,254,285	$	2,185,420







Unit-based compensation	42	387		—	—		—		—		387



Distribution equivalent rights payments	—	(20)		—	—		—		—		(20)
Distributions to public	—	(30,194)		—	—		—		—		(30,194)
Distributions to Diamondback	—	(329)		—	(25)		—		(40,819)		(41,173)
Distributions to General Partner	—	—		—	—		(20)		—		(20)

Units repurchased for tax withholding	(17)	(383)		—	—		—		—		(383)
Net (loss) income	—	(142,169)		—	—		—		18,319		(123,850)
Balance at March 31, 2020	67,831	756,408		90,710	1,105		869		1,231,785		1,990,167




Unit-based compensation	—	283		—	—		—		—		283
Distribution equivalent rights payments	—	(4)		—	—		—		—		(4)



Distributions to public	—	(6,710)		—	—		—		—		(6,710)
Distributions to Diamondback	—	(76)		—	(25)		—		(9,074)		(9,175)
Distributions to General Partner	—	—		—	—		(20)		—		(20)


Net loss	—	(21,752)		—	—		—		(11,304)		(33,056)
Balance at June 30, 2020	67,831	$	728,149	90,710	$	1,080	$	849	$	1,211,407	$	1,941,485

Limited Partners General Partner Non-Controlling Interest
Common Class B Amount Amount
Units Amount Units Amount Total
(In thousands)
Balance at December 31, 2017 113,882
$ 913,908
—
$ —
$ —
$ —
$ 913,908
Impact of adoption of ASU 2016-01 (Note 2) (18,651 ) —
—
—
(18,651 )
Unit-based compensation
1,288

—
—
—
1,288
Distributions to public
(18,737 )
—
—
—
(18,737 )
Distributions to Diamondback
(33,649 )
—
—
—
(33,649 )
Net income
42,896

—
—
—
42,896
Balance at March 31, 2018 113,882
$ 887,055
—
$ —
$ —
$ —
$ 887,055
Unit exchange related to tax conversion (73,150 ) (545,441 ) 73,150
1,000
1,000
545,441
2,000
Recapitalization related to tax conversion 732
—
(732 ) (10 ) —
—
(10 )
Unit-based compensation 7
452
—
—
—
452
Distributions to public
(19,551 ) —
—
—
(19,551 )
Distributions to Diamondback (35,112 ) —
—
—
(35,112 )
Net income 99,404
—
—
29,060
128,464
Balance at June 30, 2018 41,471
$ 386,807
72,419
$ 990
$ 1,000
$ 574,501
$ 963,298

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Changes to Unitholders' Equity - Continued

(Unaudited)


	Limited Partners												General Partner		Non-Controlling Interest
	Common			Class B			Amount		Amount
	Units	Amount		Units	Amount									Total
	(In thousands)
Balance at December 31, 2018	51,654	$	540,112	72,419	$	990	$	1,000	$	694,940	$	1,237,042



Net proceeds from the issuance of common units - public	10,925	340,648		—	—		—		—		340,648



Unit-based compensation	60	405		—	—		—		—		405



Distributions to public	—	(25,970)		—	—		—		—		(25,970)
Distributions to Diamondback	—	(392)		—	—		—		(36,934)		(37,326)
Distributions to General Partner	—	(20)		—	—		—		—		(20)
Change in ownership of consolidated subsidiaries, net	—	(71,195)		—	—		—		90,120		18,925
Units repurchased for tax withholding	(11)	(353)		—	—		—		—		(353)
Net income	—	33,779		—	—		—		40,532		74,311
Balance at March 31, 2019	62,628	817,014		72,419	990		1,000		788,658		1,607,662



Offering costs	—	(9)		—	—		—		—		(9)
Unit-based compensation	—	472		—	—		—		—		472



Distributions to public	—	(23,521)		—	—		—		—		(23,521)
Distributions to Diamondback	—	(298)		—	—		—		(27,519)		(27,817)
Distributions to General Partner	—	(20)		—	—		—		—		(20)


Net income	—	2,265		—	—		—		45,009		47,274
Balance at June 30, 2019	62,628	$	795,903	72,419	$	990	$	1,000	$	806,148	$	1,604,041

Limited Partners General Partner Non-Controlling Interest
Common Class B Amount Amount
Units Amount Units Amount Total
(In thousands)
Balance at December 31, 2018 51,654
$ 540,112
72,419
$ 990
$ 1,000
$ 694,940
$ 1,237,042
Net proceeds from the issuance of common units - public 10,925
340,648
—
—
—
340,648
Unit-based compensation 60
405
—
—
—
405
Distributions to public (25,970 ) —
—
—
(25,970 )
Distributions to Diamondback (392 ) —
—
(36,934 ) (37,326 )
Distributions to General Partner (20 ) —
—
—
(20 )
Change in ownership of consolidated subsidiaries, net (71,195 ) —
—
90,120
18,925
Units repurchased for tax withholding (11 ) (353 ) —
—
—
(353 )
Net income 33,779
—
—
40,532
74,311
Balance at March 31, 2019 62,628
$ 817,014
72,419
$ 990
$ 1,000
$ 788,658
$ 1,607,662
Offering costs (9 ) —
—
—
(9 )
Unit-based compensation

472
—
—
—
472
Distributions to public (23,521 ) —
—
—
(23,521 )
Distributions to Diamondback (298 ) —
—
(27,519 ) (27,817 )
Distributions to General Partner (20 ) —
—
—
(20 )
Net income 2,265
—
—
45,009
47,274
Balance at June 30, 2019 62,628
$ 795,903
72,419
$ 990
$ 1,000
$ 806,148
$ 1,604,041

See accompanying notes to consolidated financial statements.

Table of Contents

Viper Energy Partners LP

Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2020		2019
	(In thousands)
Cash flows from operating activities:
Net (loss) income	$	(156,906)	$	121,585
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Provision for (benefit from) income taxes	142,466		(34,536)
Depletion	47,424		32,711

Loss on derivative instruments, net	42,385		—
Net cash payments on derivatives	(2,554)		—

Gain on extinguishment of debt	(14)		—
Loss (gain) on revaluation of investment	6,677		(3,642)
Amortization of debt issuance costs	1,152		441
Non-cash unit-based compensation	670		877

Changes in operating assets and liabilities:

Royalty income receivable, net	25,971		(7,996)
Royalty income receivable—related party	9,659		(5,549)


Accounts payable and accrued liabilities	(832)		(2,238)

Accounts payable—related party	(150)		—
Income tax payable	—		108
Other current assets	(85)		(41)
Net cash provided by operating activities	115,863		101,720
Cash flows from investing activities:

Acquisitions of oil and natural gas interests	(65,272)		(125,231)



Funds held in escrow	—		(13,215)


Net cash used in investing activities	(65,272)		(138,446)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	92,000		171,000
Repayment on credit facility	(35,000)		(369,500)

Debt issuance costs	(44)		(258)
Repayment of senior notes	(13,787)		—
Proceeds from public offerings	—		340,860
Public offering costs	—		(221)



Units purchased for tax withholding	(383)		(353)
Distributions to General Partner	(40)		(40)
Distributions to public	(36,928)		(49,491)
Distributions to Diamondback	(50,348)		(65,143)
Net cash (used in) provided by financing activities	(44,530)		26,854
Net increase (decrease) in cash	6,061		(9,872)
Cash and cash equivalents at beginning of period	3,602		22,676
Cash and cash equivalents at end of period	$	9,663	$	12,804

Supplemental disclosure of cash flow information:
Interest paid	$	17,918	$	2,382

Six Months Ended June 30,
2019 2018
(In thousands)
Cash flows from operating activities:
Net income $ 121,585
$ 171,360
Adjustments to reconcile net income to net cash provided by operating activities:
Benefit from deferred income taxes (34,536 ) (72,049 )
Depletion 32,711
24,785
Gain on revaluation of investment (3,642 ) (5,364 )
Amortization of debt issuance costs 441
322
Non-cash unit-based compensation 877
1,740
Changes in operating assets and liabilities:
Royalty income receivable (7,996 ) (5,329 )
Royalty income receivable—related party (5,549 ) (2,995 )
Accounts payable and other accrued liabilities (2,238 ) (440 )
Income tax payable 108
171
Other current assets (41 ) 11
Net cash provided by operating activities 101,720
112,212
Cash flows from investing activities:
Acquisition of oil and natural gas interests (125,231 ) (253,056 )
Funds held in escrow (13,215 ) —
Proceeds from sale of assets —
441
Proceeds from the sale of investments —
125
Net cash used in investing activities (138,446 ) (252,490 )
Cash flows from financing activities:
Proceeds from borrowings under credit facility 171,000
256,500
Repayment on credit facility (369,500 ) —
Debt issuance costs (258 ) (440 )
Proceeds from public offerings 340,860
—
Public offering costs (221 ) (2,034 )
Contributions by members —
2,000
Units purchased for tax withholding (353 ) —
Distributions to partners (114,674 ) (107,059 )
Net cash provided by financing activities 26,854
148,967
Net increase (decrease) in cash (9,872 ) 8,689
Cash and cash equivalents at beginning of period 22,676
24,197
Cash and cash equivalents at end of period $ 12,804
$ 32,886

Supplemental disclosure of cash flow information:
Interest paid $ 2,382
$ 5,028

See accompanying notes to consolidated financial statements.

Table of Contents

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 listed on the Nasdaq Global Select Market under the symbol “VNOM”.~~partnership. The Partnership was formed by Diamondback Energy, Inc. (“Diamondback”) on February 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian Basin and Eagle Ford Shale. ~~Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of~~Since May 10, 2018, the Partnership ~~and its consolidated subsidiary, Viper Energy Partners LLC (the “Operating Company”).~~has been treated as a corporation for U.S. federal income tax purposes.

As of June 30, ~~2019,~~2020, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback had an approximate ~~54%~~58% limited partner interest in the Partnership. Diamondback owns and controls the General Partner.

~~Recapitalization, Tax Status Election and Related Transactions~~

In March 2018, the Board of Directors of the General Partner unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 the Partnership (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with Diamondback and (iv) entered into an exchange agreement with Diamondback, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback delivered and assigned to the Partnership the 73,150,000 common units Diamondback owned in exchange for (i) 73,150,000 of the Partnership’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, the Partnership continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and Diamondback owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of the Partnership’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and Diamondback owned the remaining approximately 59%. The Operating Company units and the Partnership’s Class B units 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).

On May 10, 2018, the change in the Partnership’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to the Partnership in respect of its general partner interest and (ii) Diamondback made a cash capital contribution of $1.0 million to the Partnership in respect of the Class B units. Diamondback, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, Diamondback also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and Diamondback continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to the Partnership’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Basis of Presentation

The accompanying consolidated financial statements and related notes thereto were prepared in ~~conformity~~accordance with GAAP. All material intercompany balances and transactions ~~are~~have been eliminated inupon consolidation.

~~Table of Contents~~

~~Viper Energy Partners LP~~

~~Condensed Notes to Consolidated Financial Statements~~

~~(Unaudited)~~

These 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 ~~such~~SEC rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This ~~Quarterly Report on Form 10–Q~~report should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, ~~2018,~~2019, which contains a summary of the Partnership’s significant accounting policies and other disclosures.

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 at the date of the financial statements.

Making accurate estimates and assumptions is particularly difficult as the oil and gas industry experiences challenges resulting from negative pricing pressure from the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets. Many companies in the oil and natural gas industry have changed near term business plans in response to changing market conditions. The aforementioned circumstances generally increase the estimation uncertainty in the Partnership’s accounting estimates, particularly the accounting estimates 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 ~~the~~each 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~~the recoverability of costs of unevaluated properties, fair value estimates of commodity derivatives, unit–based ~~compensation.~~compensation and estimate of income taxes.

~~Investments~~

The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method. This investment is presented on the balance sheet as other long-term assets. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. See Note 12—Fair Value Measurements for additional disclosure regarding the impact of the fair value measurement of this investment.

~~Income Taxes~~

The Partnership uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Partnership is subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 7—Related Party Transactions. In addition to the 2018 tax year, the Partnership’s 2015 through 2017 tax years, periods during which the Partnership was organized as a pass-through entity for income tax purposes, remain open to examination by tax authorities. As of June 30, 2019, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the three and six months ended June 30, 2019, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.

Table of Contents

Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

~~(unaudited)~~(Unaudited)

Accounts Receivable

~~New Accounting Pronouncements~~

Accounts receivable consist of receivables from oil and natural gas sales. The operators remit payment for production directly to the Partnership. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work which is required to be completed by the operator before payments are released.

~~Recently Adopted Pronouncements~~

~~In February 2016, the Financial Accounting Standards Board issued~~The Partnership adopted 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~~(“ASU”) 2016-13 and 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 changessubsequent applicable modifications to the ~~lessor accounting, changes were~~rule on January 1, 2020. Accounts receivable are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Partnership when collection is deemed doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines its allowance by considering a number of factors, including the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to the Partnership, the condition of the general economy and the industry as a whole. The Partnership writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. The adoption of ASU 2016-13 did not result in a material change to the Partnership’s allowance, and no cumulative-effect adjustment was made to ~~align key aspects with~~beginning unitholders’ equity. At June 30, 2020, the ~~revenue recognition guidance. This update~~Partnership recorded an immaterial allowance for expected losses and did 0t record such an allowance at December 31, 2019.

Derivative Instruments

The Partnership is ~~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~~its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the ~~beginning~~changes in fair value of a derivative depends on the intended use of the ~~earliest~~derivative and resulting designation. 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 change in fair value on derivative instruments for each period ~~presented using~~in the consolidated statements of operations.

Accrued Liabilities

Accrued liabilities consist of the following:


	June 30,		December 31,
	2020		2019
	(In thousands)
Interest payable	$	4,391	$	6,718
Ad valorem taxes payable	3,324		5,632
Derivatives payable	4,627		—
Other	97		932
Total accrued liabilities	$	12,439	$	13,282

Non-controlling Interest

Non-controlling interest in the accompanying consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. When Diamondback’s relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity, tax effected, will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a ~~modified retrospective approach. As~~change of ~~June 30,~~control, the transactions were accounted for as equity transactions under ASC Topic 810, Consolidation, which requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. In the first quarter of 2019, the Partnership recorded an adjustment to non-controlling interest of $90.1 million, common unitholder equity of $(71.2) million, and deferred tax asset of $18.9 million to reflect the ownership structure that was ~~not the lessor or lessee of any leases other than mineral leases which were excluded from the scope of this Accounting Standards Update.~~effective at March 31, 2019. The ~~Partnership adopted this update effective January 1, 2019. It did not have a material~~adjustment had no impact on ~~its financial position, results~~earnings. See Note 7 - Unitholders' Equity and Partnership Distributions for further discussion of ~~operations or liquidity.~~

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sectionschange in the new lease guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In January 2019, the Financial Accounting Standards Board issued Accounting Standards Update 2019-01, “Leases (Topic 842): Codification Improvements”. This update clarifies certain presentation and transition disclosures under Topic 842. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

ownership.

Table of Contents

Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

~~(unaudited)~~(Unaudited)

Recent Accounting Pronouncements

~~In July 2018,~~

The Partnership considers the ~~Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update~~applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides ~~clarification~~a brief description of recent accounting pronouncements and ~~corrects unintended application~~the Partnership’s analysis of the guidance in various sections. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership adopted this update effective January 1, 2019. It did not have a material impacteffects on its financial ~~position, results of operations or liquidity.~~statements:

Standard

Description

Date of Adoption

Effect on Financial Statements or Other Significant Matters

Recently Adopted Pronouncements

ASU 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 affect 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.

Q1 2020

The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.

Pronouncements Not Yet Adopted

ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”

This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.

Q1 2021

This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.

~~Accounting Pronouncements Not Yet Adopted~~

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 affect 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 does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. 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 does not believe the adoption of this standard will have an impact on its financial statements since it does not have a history of credit losses.

In April 2019, the Financial Accounting Standards Board issued Accounting Standards Update 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments”. This update clarifies guidance previously issued in ASU 2016-01, ASU 2016-13 and ASU 2017-12. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Partnership does not believe the updates to the referenced standards will have an impact on its financial position, results of operations or liquidity.

In May 2019, the Financial Accounting Standards Board issued Accounting Standards Update 2019-05, “Financial Instruments-Credit Losses (Topic 326)”. This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Partnership does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. 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 prospectively. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Effective January 1, 2018, the Partnership adopted the Financial Accounting Standards Board Accounting Standards Update 2014-09, “Revenue from Contracts with Customers” using the modified retrospective method. The adoption of this standard did not result in a cumulative-effect adjustment.

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is ~~recognized~~recognized at the point control of the product is transferred to the ~~purchaser. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index.~~

~~Table of Contents~~

~~Viper Energy Partners LP~~

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

~~(unaudited)~~

~~Royalty income from oil, natural gas and natural gas liquids sales~~

The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser or operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

~~Transaction price allocated to remaining performance obligations~~

The following table disaggregates the Partnership’s ~~right to~~total royalty income ~~does not originate until production occurs~~by product type:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(In thousands)
Oil income	$	27,617	$	65,863	$	99,817	$	117,850
Natural gas income	1,234		(1,074)		1,578		2,765
Natural gas liquids income	3,593		5,653		7,878		10,255
Total royalty income	$	32,444	$	70,442	$	109,273	$	130,870

4. ACQUISITIONS

2020 Activity

During the six months ended June 30, 2020, the Partnership acquired, from unrelated third-party sellers, mineral and ~~therefore, is not considered~~royalty interests representing 4,948 gross (410 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $63.4 million, subject to ~~exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of the Partnership’s royalty income contracts.~~

~~Contract balances~~

Under the Partnership’s royalty income contracts, it would have the right to receive royalty income once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

~~Prior-period performance obligations~~

post-closing adjustments. The Partnership ~~records revenue in~~funded these acquisitions with cash on hand and borrowings under the ~~month production is delivered. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30~~Operating Company’s revolving credit facility.

Table of Contents

Viper Energy Partners LP

Condensed Notes to ~~90 days after~~Consolidated Financial Statements - (Continued)

(Unaudited)

2019 Activity

During the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Partnership has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three and six months ended June 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

~~4. ACQUISITIONS~~

~~2019 Activity~~

~~During the~~ ~~six months ended June 30, 2019~~, the Partnership acquired, from unrelated ~~third parties~~third-party sellers, mineral and royalty interests ~~underlying~~representing 1,028 net royalty acres for an aggregate purchase price of approximately $126.9 ~~million and, as of June 30, 2019, had mineral interests underlying 15,870 net royalty acres.~~million. The Partnership funded these acquisitions with cash on hand, a portion of the net proceeds from its February 2019 offering of common units and borrowings under ~~its revolving credit facility.~~

~~2018 Activity~~

~~During~~ the six months ended June 30, 2018, the Partnership acquired mineral interests underlying 1,891 net royalty acres for an aggregate purchase price of approximately $260.8 million and, as of June 30, 2018, had mineral interests underlying 11,451 net royalty acres. The Partnership funded these acquisitions with cash on hand and borrowings under itsOperating Company’s revolving credit facility.

~~Table of Contents~~

~~Viper Energy Partners LP~~

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

~~(unaudited)~~

5. OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:


	June 30,		December 31,
	2020		2019

	(In thousands)
Oil and natural gas interests:
Subject to depletion	$	1,453,385	$	1,316,692
Not subject to depletion	1,480,346		1,551,767
Gross oil and natural gas interests	2,933,731		2,868,459
Accumulated depletion and impairment	(373,898)		(326,474)
Oil and natural gas interests, net	2,559,833		2,541,985
Land	5,688		5,688
Property, net of accumulated depletion and impairment	$	2,565,521	$	2,547,673

June 30, December 31,
2019 2018

(in thousands)
Oil and natural gas interests:
Subject to depletion $ 909,093
$ 845,228
Not subject to depletion 932,938
871,485
Gross oil and natural gas interests 1,842,031
1,716,713
Accumulated depletion and impairment (281,007 ) (248,296 )
Oil and natural gas interests, net 1,561,024
1,468,417
Land 5,688
5,688
Property, net of accumulated depletion and impairment $ 1,566,712
$ 1,474,105

Balance of costs not subject to depletion:
Incurred in 2019 $ 106,811

Incurred in 2018 464,763

Incurred in 2017 284,371

Incurred in 2016 76,993

Total not subject to depletion $ 932,938

As of June 30, 2020 and December 31, 2019, the Partnership had mineral and royalty interests representing 24,714 and 24,304 net royalty acres, respectively.

Costs associated with unevaluated interests are excluded from the full cost pool until a determination as to the existence 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 years to five years.

Under the full cost method of accounting, the Partnership is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas interests. ~~Net capitalized costs are limited~~After performing the ceiling test for the quarter ended June 30, 2020, the Partnership was not required 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 revenue including estimated expenditures (based on current costs) to be incurred in developing and producing the proved reserves, discounted at 10% per annum, from proved reserves, based onrecord an impairment. If the trailing 12-month ~~unweighted average of~~commodity prices continue to fall as compared to the ~~first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge~~commodity prices used in prior quarters, the ~~Partnership’s oil and natural gas revenue, (b) the cost of interests not being amortized, if any, and (c) the lower of cost or market value of unproved interests included~~Partnership will have write-downs in ~~the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write down is required.~~subsequent quarters, which may be material.

6. DEBT

~~Credit Agreement-Wells Fargo Bank~~Long-term debt consisted of the following as of the dates indicated:


	June 30,		December 31,
	2020		2019
	(In thousands)
5.375% Senior Notes due 2027	$	485,938	$	500,000
Revolving credit facility	153,500		96,500
Unamortized debt issuance costs	(2,237)		(2,458)
Unamortized discount costs	(6,694)		(7,268)
Total long-term debt	$	630,507	$	586,774

On July 8, 2014, the Partnership entered into a secured revolving credit agreement as amended and restated, (the “credit facility”) with Wells Fargo, as administrative agent, certain other lenders, and the Partnership’s consolidated subsidiary,

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Viper Energy Partners ~~LLC~~LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

2027 Senior Notes

On October 16, 2019, the Partnership completed an offering (the ~~“Operating Company”~~“Notes Offering”)~~, as guarantor. On May 8, 2018,~~ of $500.0 million in aggregate principal amount of its 5.375% Senior Notes due 2027 (the “Notes”). The Partnership received net proceeds of approximately $490.0 million from the Notes Offering. The Partnership loaned the gross proceeds to the Operating Company. The Operating Company ~~assumed all liabilities as borrower~~used the proceeds from the Notes Offering to pay down borrowings under its revolving credit facility. During the ~~credit agreement and~~second quarter of 2020, the Partnership ~~became a guarantor~~repurchased $14.1 million of the ~~credit agreement.~~ outstanding principal of the Notes at a cash price ranging from 97.5% to 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt. As of June 30, 2020, the remaining outstanding principal amount of Notes totaled $485.9 million and will mature on November 1, 2027.

The Operating Company’s Revolving Credit Facility

On July 20, 2018, the Partnership, as guarantor, entered into an amended and restated credit agreement with the Operating Company, ~~the Partnership,~~as borrower, Wells Fargo National Bank (“Wells Fargo”), as administrative agent, and the other ~~lenders amended and restated the credit agreement to reflect the assumption by the Operating Company.~~lenders. The credit agreement, as amended ~~and restated,~~to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on ~~its~~the Operating Company’s oil and natural gas reserves and other ~~factors (the “borrowing base”) of $600.0~~factors. The Partnership’s borrowing base was reduced from $775.0 million ~~subject~~ to $580.0 million during the scheduled semi-annual ~~and other borrowing base redeterminations.~~redetermination in the second quarter of 2020. The borrowing base is scheduled to be re-determined semi-annually ~~with effective dates of~~in May ~~1st~~ and ~~November 1st.~~November. In addition, the Operating Company and Wells Fargo each may request up to ~~three~~3 interim redeterminations of the borrowing base during any 12-month period. ~~Effective June 27, 2019, in connection with the Partnership’s spring 2019 redetermination, the borrowing base increased from $555.0 million to $600.0 million and, as~~As of June 30, ~~2019,~~2020, there was ~~$212.5 million of outstanding borrowings and $387.5~~$426.5 million available for future borrowings under the ~~credit facility.~~

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~~Viper Energy Partners LP~~

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

~~(unaudited)~~

~~The outstanding borrowings under the credit agreement bear interest at a rate elected by the~~ Operating Company 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 0.75% to 1.75% per annum in the case of the alternative base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may 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 the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of the Partnership and the Operating Company.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, 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 Covenant~~		~~Required Ratio~~
~~Ratio of total net debt to EBITDAX, as defined in the credit agreement~~		~~Not greater than 4.0 to 1.0~~
~~Ratio of current assets to liabilities, as defined in the credit agreement~~		~~Not less than 1.0 to 1.0~~

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 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.

~~As of June 30, 2019, the Operating Company was in compliance with the financial covenants under its credit agreement. The lenders may accelerate all of the indebtedness under the~~Company’s revolving credit facility 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. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

~~7. RELATED PARTY TRANSACTIONS~~

~~Partnership Agreement~~

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (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 six months ended June 30, 2019 and 2018, the General Partner allocated $0.6 million and $1.2 million, respectively, to the Partnership.

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~~Viper Energy Partners LP~~

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

~~(unaudited)~~

~~Advisory Services Agreement~~

In connection 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 provided 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 was terminated on November 12, 2018 and the Partnership’s payment obligation ended in June 2019. For the three and six months ended June 30, 2019 and 2018, the Partnership did not pay any amounts 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 Diamondback 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. For the three months ended June 30, 2019 and 2018, the Partnership accrued state income tax expense of less than $0.1 million and $0.2 million, respectively, and for the six months ended June 30, 2019 and 2018, the Partnership accrued state income tax expense of $0.1 million and $0.2 million, respectively, for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback.

~~Lease Bonus~~

During the three months ended June 30, 2019, Diamondback paid the Partnership $39,000 in lease bonus payments to extend the term of one lease, reflecting an average bonus of $1,800 per acre. During the six months ended June 30, 2019, Diamondback paid the Partnership $39,198 in lease bonus payments to extend the term of two leases, reflecting an average bonus of $1,686 per acre and $3,101 in lease bonus payments for two new leases, reflecting an average bonus of $14,766 per acre.facility. During the three and six months ended June 30, ~~2018, Diamondback did not pay~~2020, the ~~Partnership any lease bonus payments.~~

~~8. UNIT-BASED COMPENSATION~~

weighted average interest rates on the Operating Company’s revolving credit facility were 2.41% and 2.82%, respectively. The revolving credit facility will mature on November 1, 2022.

In connection with the IPO, 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, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards.

As of June 30, ~~2019, a total of 8,943,717~~2020, the Operating Company was in compliance with th common units 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.e financial maintenance covenants under its credit agreement.

~~For the three and six months ended June 30, 2019, the Partnership incurred $0.5 million and $0.9 million, respectively, 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.

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~~Viper Energy Partners LP~~

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

~~(unaudited)~~

~~The following table presents the phantom unit activity under the LTIP for the six months ended June 30, 2019:~~

Phantom
Units Weighted Average
Grant-Date
Fair Value
Unvested at December 31, 2018 125,053
$ 23.44
Granted 17,601
$ 33.54
Vested (60,133 ) $ 21.38
Forfeited (1,028 ) $ 42.50
Unvested at June 30, 2019 81,493
$ 26.91

The aggregate fair value of phantom units that vested during the six months ended June 30, 2019 was $1.3 million. As of June 30, 2019, the unrecognized compensation cost related to unvested phantom units was $1.3 million. Such cost is expected to be recognized over a weighted-average period of 0.85 years.

9.7. UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and ~~limited~~limited partner units. At June 30, ~~2019,~~2020, the Partnership had a total of ~~62,628,357~~67,831,342 common units issued and outstanding and ~~72,418,500~~90,709,946 Class B units issued and outstanding, of which 731,500 common units and ~~72,418,500~~90,709,946 Class B units were owned by Diamondback, representing approximately ~~54%~~58% of the Partnership’s total ~~Partnership’s~~ units outstanding. The Operating Company units and the Partnership’s Class B units 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).

~~The following table summarizes changes in the number of the Partnership’s common units:~~



	~~Common Units~~
~~Balance at December 31, 2018~~	~~51,653,956~~
~~Common units issued in public offerings~~	~~10,925,000~~
~~Common units vested and issued under the LTIP~~	~~60,133~~
~~Units repurchased for tax withholding~~	~~(10,732~~	)
~~Balance at June 30, 2019~~	~~62,628,357~~

~~The Partnership had a total of 72,418,500 Class B units outstanding as of June 30, 2019 and December 31, 2018, respectively.~~

In ~~February~~March 2019, the Partnership completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximately 54% of the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $340.6 million, after deducting underwriting discounts and commissions and offering expenses. The Partnership used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under ~~the~~its revolving credit facility and finance acquisitions during the period.

~~The board of directors of the General Partner has adopted a policy for the Partnership to distribute on a quarterly basis all available cash it receives from the Operating Company.~~

The following table ~~presents information regarding cash distributions approved by~~summarizes the ~~board of directors of~~ownership interest in subsidiary changes during the ~~General Partner for the periods presented:~~period:

Amount per Common Unit Declaration Date Unitholder Record Date Payment Date
Q4 2018 $ 0.51

January 30, 2019

February 19, 2019

February 25, 2019
Q1 2019 $ 0.38

April 25, 2019

May 13, 2019

May 20, 2019


	Six Months Ended June 30, 2019
	(In thousands)
Net income attributable to the Partnership	$	36,044

Change in ownership of consolidated subsidiaries due to purchase of subsidiary shares in 2019 offering	(71,195)




Change from net loss attributable to the Partnership's shareholders and transfers to non-controlling interest	$	(35,151)

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

~~(unaudited)~~(Unaudited)

There were 0 changes in ownership of consolidated subsidiaries during the three and six months ended June 30, 2020 and the three months ended June 30, 2019.

~~Cash distributions will be made~~Beginning with the first quarter of 2020, the board of directors of the General Partner revised the distribution policy pursuant to which the Operating Company now distributes 25% of the available cash it generates each quarter to its unitholders (including the Partnership), and pursuant to which the Partnership in turn distributes all of the available cash it receives from the Operating Company to its common ~~unitholders~~unitholders. The Partnership’s available cash, and the available cash of ~~record on~~ the ~~applicable record date, generally within 60 days after the end of each quarter. Available cash~~Operating Company, for each quarter ~~will be~~is determined by the board of directors of the General Partner following the end of such quarter. ~~Available~~The Operating Company’s available cash ~~for each quarter will~~ generally ~~equal~~equals its Adjusted EBITDA ~~reduced~~ for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors of the General Partner deems necessary or appropriate, if any. The Partnership’s available cash for each quarter generally equals its Adjusted EBITDA (which is the Partnership’s proportional share of the available cash of the Operating Company for the quarter), less cash needed for the payment of income taxes by it, if any, and the preferred distribution. Immediately prior to the adoption of this policy, the Operating Company’s policy was to distribute all of its available cash quarterly to its unitholders rather than 25%. The distribution policy was changed to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet.

The board of directors of the General Partner may change the distribution policies at any time. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other basis.

~~10.~~

The following table presents information regarding cash distributions approved by the board of directors of the General Partner for the periods presented:

Amount per Common Unit

Declaration Date

Unitholder Record Date

Payment Date

Q4 2019

0.45

February 7, 2020

February 21, 2020

February 28, 2020

Q1 2020

0.10

April 30, 2020

May 14, 2020

May 21, 2020

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.

Amendment to LLC Agreement - Tax Allocation

On March 30, 2020, the Partnership, as managing member of the Operating Company, entered into the First Amendment to Second Amended and Restated Limited Liability Company Agreement of the Operating Company (the “Amendment”) to extend the remaining period of special allocations to Diamondback of the Operating Company’s income and gains over losses and deductions (but before depletion) from two to four years.

8. EARNINGS PER COMMON UNIT

The net (loss) income per common unit on the consolidated statements of operations is based on the net (loss) income of the Partnership for the three and six months ended June 30, ~~2019~~2020 and ~~2018,~~2019, since this is the amount of net (loss) income that is attributable to the Partnership’s common units.

The Partnership’s net (loss) income is allocated wholly to the common ~~units.~~units, as the General Partner does not have an economic interest. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note 9—7—Unitholders' Equity and Partnership Distributions.

Basic net (loss) income per common unit is calculated by dividing net (loss) income by the weighted-average number of common units outstanding during the period. Diluted net (loss) income per common unit gives effect, when applicable, to unvested common units granted under the LTIP.

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 2019 2018
(In thousands, except per unit amounts)
Net income attributable to the period $ 2,265
$ 99,404
$ 36,044
$ 142,300
Weighted average common units outstanding:
Basic weighted average common units outstanding 62,628
73,336
59,058
93,506
Effect of dilutive securities:
Potential common units issuable 36
91
36
106
Diluted weighted average common units outstanding 62,664
73,427
59,094
93,612
Net income per common unit, basic $ 0.04
$ 1.36
$ 0.61
$ 1.52
Net income per common unit, diluted $ 0.04
$ 1.35
$ 0.61
$ 1.52

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(In thousands, except per unit amounts)
Net (loss) income attributable to the period	$	(21,752)	$	2,265	$	(163,921)	$	36,044
Less: net loss allocated to participating securities⁽¹⁾	(4)		(21)		(24)		(63)
Net (loss) income attributable to common unitholders	$	(21,756)	$	2,244	$	(163,945)	$	35,981


Weighted average common units outstanding:
Basic weighted average common units outstanding	67,831		62,628		67,827		59,058
Effect of dilutive securities:
Potential common units issuable⁽²⁾	—		36		—		36
Diluted weighted average common units outstanding	67,831		62,664		67,827		59,094
Net (loss) income per common unit, basic	$	(0.32)	$	0.04	$	(2.42)	$	0.61
Net (loss) income per common unit, diluted	$	(0.32)	$	0.04	$	(2.42)	$	0.61

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

(2) For the three ~~months ended June 30, 2019~~ and ~~2018, there were no common units and 560 common units, respectively, and for~~ six months ended June 30, ~~2019 and 2018, there were no~~2020, 0 potential common units ~~and 1,234 common units, respectively, that~~ were ~~not~~ included in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive under the treasury stock method for the periods presented but could potentially dilute basic earnings per common unit in future periods.

~~11.~~9. INCOME TAXES

As discussed further in Note 1—Organization and Basis of Presentation, on March 29, 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes for the period ended June 30, 2019 is based on the estimated annual effective tax rate plus discrete items.

The Partnership’s effective income tax rates were ~~0.4%~~0% and ~~(127.0)%~~0.4% for the three months ended June 30, 2020 and 2019, respectively, and ~~2018, respectively, and (39.50)~~(986.6)% ~~and (72.25)~~and (39.5)% for the six months ended June 30, 2020 and 2019, respectively. Total income tax expense for the three and ~~2018, respectively.~~ six months ended June 30, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period, primarily due to net income attributable to the non-controlling interest and the impact of recording a valuation allowance on the Partnership’s deferred tax assets.

Total income tax benefit for the three and six months ended June 30, 2019 differed from amounts computed by applying the United States federal statutory ~~tax~~ rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and, for the six months ended June 30, 2019, ~~due to~~ the revision of estimated deferred taxes recognized as a result of the Partnership’s ~~change in tax status and net income attributable~~election to ~~the non-controlling interest. Total~~be treated as a corporation for U.S. federal income tax ~~benefit for~~purposes effective May 10, 2018.

For the ~~three and~~ six months ended June 30, ~~2018 differed from amounts computed by applying~~2020, the ~~United States federal statutory rate to pre-tax~~Partnership’s total income tax provision includes a discrete income tax expense of approximately $142.5 million recorded for the ~~period~~three months ended March 31, 2020, related to application of a full valuation allowance on the Partnership’s beginning-of-the-year deferred tax assets, which consist primarily

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~~Viper Energy Partners LP~~

~~Condensed Notes~~its investment in the Operating Company and federal net operating loss carryforwards. A valuation allowance was also applied against the year-to-date tax benefit resulting from the Partnership’s projected pretax loss for the year. The determination to ~~Consolidated Financial Statements - (Continued)~~

~~(unaudited)~~

~~due to (i) the impact~~record a valuation allowance as of ~~deferred taxes recognized as a result~~March 31, 2020 was based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s ~~change in~~deferred tax ~~status, (ii) net income attributable to~~assets, as required by applicable financial accounting standards. In light of those criteria for recognizing the ~~non-controlling interest, and (iii) net income attributable to the period prior to~~tax benefit of deferred tax assets, the Partnership’s ~~change~~assessment resulted in application of a full valuation allowance against its deferred tax ~~status.~~assets as of March 31, 2020 and June 30, 2020.

For the six months ended June 30, 2019, the Partnership recorded a discrete income tax benefit of approximately $35.2 million related to the revision of estimated deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s federal tax status. Under federal income tax provisions applicable to the Partnership’s change in tax status, the Partnership’s basis for federal income tax purposes in its interest in the Operating Company ~~consists~~consisted primarily of the sum of the Partnership’s unitholders’ tax ~~bases~~basis in their interests in the Partnership on the date of the tax status change. The Partnership prepared its best estimate of the resultant tax basis in the Operating Company for purposes of the Partnership’s income tax provision for the period of the change, but information necessary for the partnership to finalize its determination iswas not ~~expected to be~~ available until unitholders’ tax basis information iswas fully reported and the Partnership ~~finalizes~~finalized its federal income tax computations for 2018. Based on information available, the Partnership revised its estimate of the difference between its tax basis and its basis for financial accounting purposes in the Operating Company on the date of the tax status

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

change, resulting in deferred income tax benefit of $35.2 million included in the Partnership’s income tax provision for the six months ended June 30, 2019.

~~Prior~~The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. This legislation included a number of provisions applicable to ~~May 10, 2018,~~U.S. income taxes for corporations, including providing for carryback of certain net operating losses, accelerated refund of minimum tax credits, and modifications to the ~~effective date~~rules limiting the deductibility of business interest expense. The Partnership has considered the impact of this legislation in the period of enactment and concluded there was not a material impact to the Partnership’s current or deferred income tax balances.

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 combined consolidated statements of operations under the caption “Loss on derivative instruments, net.”

Commodity Contracts

The Partnership uses 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. With respect to the Partnership’s fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to the Partnership if the settlement price for any settlement period is less than the swap or basis price, and the Partnership is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap or basis price. The Partnership has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price.

Under the Partnership’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Partnership and when the settlement price is above the ceiling price, the Partnership is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

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

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

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

As of June 30, 2020, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.


	2020
Swaps	Volume	Fixed Price Swap (per Bbl/MMBtu)
Oil swaps - WTI Cushing (Bbls)	184,000	$	27.45


Oil basis swaps - WTI Midland-Cushing (Bbls)	736,000	$	(2.60)

Natural gas basis swaps - Waha Hub (MMBtu)	4,600,000	$	(2.07)


Collars - WTI Cushing	2020		2021
Volume (Bbls)	2,576,000		3,650,000
Floor price (per Bbl)	$	28.86	$	30.00
Ceiling price (per Bbl)	$	32.33	$	43.05


Deferred premium call options - WTI Cushing	2020
Volume (Bbls)	736,000
Premium	$	1.89
Strike price (per Bbl)	$	45.00

Balance sheet offsetting of derivative assets and liabilities

The fair value of swaps 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.

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Partnership’s consolidated balance sheets as of June 30, 2020.


	June 30, 2020
	(In thousands)
Gross derivative assets	$	13,084
Amounts netted	(13,084)
Net derivative assets	$	—

Gross derivative liabilities	$	52,915
Amounts netted	(13,084)
Net derivative liabilities	$	39,831

The Partnership did 0t have any derivatives prior to February 2020.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Partnership’s ~~change in income tax status,~~derivative assets and liabilities and their locations on the ~~Partnership was organized~~consolidated balance sheet are as ~~a pass-through entity for income tax purposes. As a result, the Partnership’s partners were responsible for federal income taxes on their share~~follows:


	June 30, 2020
	(In thousands)
Current assets: derivative instruments	$	—
Noncurrent assets: derivative instruments	—
Total assets	$	—
Current liabilities: derivative instruments	$	33,956
Noncurrent liabilities: derivative instruments	5,875
Total liabilities	$	39,831

None of the Partnership’s ~~taxable income.~~derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:


	Three Months Ended June 30, 2020						Six Months Ended June 30,
	2020		2019		2020		2019
	(In thousands)
Loss on derivative instruments	$	(34,443)	$	—	$	(42,385)	$	—
Net cash payments on derivatives	$	(2,101)	$	—	$	(2,554)	$	—

~~12.~~11. FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

~~(unaudited)~~(Unaudited)

Assets and Liabilities Measured at Fair Value on a Recurring Basis

~~The Partnership’s cost method investment is~~

Certain assets and liabilities are reported at fair value on a recurring ~~basis.~~ basis, including the Partnership’s derivative instruments and investment, which is included in other assets on the consolidated balance sheets. The Partnership measures its investment utilizing the fair value option, and as such the investment is classified as Level 1 in the fair value hierarchy. The fair values of the Partnership’s fixed price swaps, fixed price basis swaps and costless collars 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.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2020 and December 31, 2019:


	June 30, 2020										December 31, 2019
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(In thousands)
Assets:
Investment	$	12,680	$	—	$	—	$	19,357	$	—	$	—


Liabilities:
Derivative instruments	$	—	$	(39,831)	$	—	$	—	$	—	$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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


	June 30, 2020						December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Debt:
Revolving credit facility	$	153,500	$	153,500	$	96,500	$	96,500
5.375% Senior Notes due 2027⁽¹⁾	$	477,007	$	476,462	$	490,274	$	521,100

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

The fair value of the ~~Partnership’s investment at June 30, 2019~~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 ~~December 31, 2018~~maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was determined using the June 30, ~~2019 and December 31, 2018~~2020 quoted market ~~prices. The investment is~~price, a Level 1 classification in the fair value hierarchy. ~~See Note 2—Summary~~

Fair Value of ~~Significant Accounting Policies.~~ Financial Assets

The ~~following table summarizes the changes in fair~~Partnership has other financial instruments consisting of cash and cash equivalents, accounts receivable, other current assets, accounts payable and accrued liabilities. The carrying value of ~~the Partnership’s investment:~~these instruments approximates fair value.

(in thousands)
Fair Value of investment as of December 31, 2017 $ 33,851
Impact of adoption of Accounting Standards Update 2016-01 (18,651 )
Disposal of shares (126 )
Gain on investment 5,364
Fair Value of investment as of June 30, 2018 $ 20,438

(in thousands)
Fair Value of investment as of December 31, 2018 $ 14,525
Gain on investment 3,642
Fair Value of investment as of June 30, 2019 $ 18,167

~~13.~~

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12. COMMITMENTS AND CONTINGENCIES

The Partnership ~~could be subject~~is a party to various ~~possible loss contingencies which~~routine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business, including those that arise ~~primarily~~ from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry. These proceedings, disputes and ~~crude oil industry. Such contingencies~~claims may include differing interpretations as to the prices at which crude oil and natural gas ~~and crude oil~~ sales may be made, the prices at which royalty owners may be paid for production from their leases, title claims, environmental issues and other matters. ~~Management~~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 ~~it has complied with~~that none of these matters, if ultimately decided adversely, will have a material adverse effect on the ~~various laws~~Partnership’s financial condition, results of operations or cash flows. The Partnership’s assessment is based on information known about the pending matters and ~~regulations, administrative rulings~~its experience in contesting, litigating and ~~interpretations.~~settling similar matters. Actual outcomes could differ materially from the Partnership’s assessment. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

~~14.~~

13. SUBSEQUENT EVENTS

Cash Distribution

On July ~~28, 2019~~,29, 2020, the board of directors of the General Partner approved a cash distribution for the second quarter of ~~2019~~2020 of ~~$0.47~~$0.03 per common unit, payable on August ~~21, 2019~~,20, 2020, to eligible unitholders of record at the close of business on August ~~14, 2019.~~13, 2020.

Repurchases of Notes

~~Pending Drop-Down and Anticipated Increase in the Borrowing Base under the Operating Company’s Revolving Credit Facility~~

~~Subsequent to the end of~~After the second quarter of ~~2019,~~2020, the Partnership ~~entered into a definitive purchase agreement to acquire certain mineral and royalty interests from subsidiaries of Diamondback for 18.3~~repurchased $6.0 million of the ~~Partnership’s newly-issued Class B units, 18.3 million newly-issued units~~outstanding principal of the ~~Operating Company and $150.0 million in~~Notes at a cash ~~subject to certain adjustments (the “Pending Drop-Down”). Based on the volume weighted average sales~~ price of Viper’s common units for the 10-trading day period ending July 26, 2019 of $30.07, the transaction is valued at $700.0 million. The mineral and royalty interests being acquired in the Pending Drop-Down represent approximately 5,090 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by Diamondback, and have an average net royalty interest of approximately 3.2%. After giving pro forma effect to the Pending Drop-Down, the Partnership’s mineral interests at June 30, 2019 would have totaled 20,960 net royalty acres. The Partnership anticipates closing the Pending Drop-Down during the fourth quarter of 2019. However, the Pending Drop-Down remains subject to completion of due diligence and satisfaction of other closing conditions. There can be no assurance that the Partnership will complete the Pending Drop-Down on the terms contemplated in this report or at all. The Partnership intends to finance the cash portion98.5% of the ~~purchase price~~aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt. As of July 31, 2020, the ~~Pending Drop-Down through a combination~~remaining outstanding principal amount of ~~cash on hand and borrowings under the Operating Company’s revolving credit facility.~~Notes totaled $479.9 million.

Upon closing of the Pending Drop-Down, the Partnership anticipates that the borrowing base under the Operating Company’s revolving credit facility will be increased by $125.0 million to $725.0 million from $600.0 million at June 30, 2019.

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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 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, ~~2018.~~2019. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See ~~“Part II.~~“Part II . Item 1A. Risk ~~Factors”~~Factors” and ~~“Cautionary~~“Cautionary 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, acquire and exploit oil and natural gas properties in North America. We are currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. We operate in one reportable segment. Since May 10, 2018, we have been treated as a corporation for U.S. federal income tax purposes.

As of June 30, ~~2019,~~2020, our general partner had a 100% general partner interest in us, and Diamondback owned 731,500 common units and all of our ~~72,418,500~~90,709,946 outstanding Class B units, representing approximately ~~54%~~58% of our total units outstanding. Following the completion of the Pending Drop-Down described in this report, Diamondback will own 731,500 common units and 90,709,946 Class B units, which will represent approximately 60% of our total units outstanding. See “Pending Drop-Down and Anticipated Increase in the Borrowing Base under the Operating Company’s Revolving Credit Facility” below. Diamondback also owns and controls our general partner.

~~We operate~~

Recent Developments

COVID-19 and Recent Collapse in ~~one reportable segment engaged~~Commodity Prices

On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the ~~acquisition of~~COVID-19 pandemic resulted in a widespread health crisis and a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas ~~properties. Our assets consist primarily~~and caused significant volatility and disruption of ~~producing~~the financial markets.

In early March 2020, oil prices dropped sharply and continued to decline reaching negative levels. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production, which helped to reduce a portion of the excess supply in the market and improve oil prices, there is no assurance that this agreement will continue or be observed by its parties, and downward pressure on commodity prices has continued and could continue for the foreseeable future. The Company cannot predict if or when commodity prices will stabilize and at what levels.

As a result of the reduction in crude oil demand caused by factors discussed above, Diamondback and other operators on properties in which we have mineral and royalty interests lowered their 2020 capital budgets and production guidance, curtailed near term production and reduced their rig count, all of which may be subject to further reductions or curtailments if the commodity markets and macroeconomic conditions do not improve or worsen. Although Diamondback and certain of our other operators have recently moved to restore curtailed production, actions taken by our operators in response to the COVID-19 pandemic and depressed commodity pricing environment have had and are expected to continue to have an adverse effect on our business, financial results and cash flows.

Based on the results of the quarterly ceiling test, we were not required to record an impairment on our proved oil and natural gas interests ~~principally located in the Permian Basin of West Texas.~~

~~Sources of Our Income~~

Our income is primarily derived from royalty payments we receive from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. Royalty payments may vary significantly from period to period as a result of commodity prices, production mix and volumes of production sold by our operators.

~~The following table presents the breakdown of our operating income~~ for the ~~following periods:~~

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 2019 2018
Operating income:
Royalty income
Oil sales 91 % 88 % 88 % 88 %
Natural gas sales (1 )% 3 % 2 % 4 %
Natural gas liquid sales 8 % 8 % 8 % 7 %
Lease bonus income 2 % 1 % 2 % 1 %
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 2018, NYMEX - West Texas Intermediate Futures Contract 1 prices ranged from $42.53 to $76.41 per Bbl and the NYMEX Natural Gas Futures Contract 1 prices ranged from $2.55 to $4.84 per MMBtu. During the first six months of 2019, NYMEX - West Texas Intermediate Futures Contract 1 prices ranged from $46.54 to $66.30 per Bbl and the NYMEX Natural Gas Futures Contract 1 prices ranged from $2.19 to $3.59 per MMBtu. On June 28, 2019, the NYMEX - West Texas Intermediate Futures Contract 1 prices for crude oil was $58.47 per Bbl and the NYMEX Natural Gas Futures Contract 1 price was $2.31 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 the credit agreement, which may be redetermined at the discretion of our lenders.

~~Table of Contents~~

~~Recent Acquisitions~~

~~During the six months~~quarter ended June 30, ~~2019,~~2020. If commodity prices fall below current levels, we ~~acquired from unrelated third parties 1,028 net royalty acres~~may be required to record impairments in ~~74 acquisitions for an aggregate purchase price~~future periods and such impairments could be material. Further, if commodity prices fail to stabilize or decrease further, our production, proved reserves and cash flows will be adversely impacted. Our business may be also further adversely impacted by any pipeline capacity and storage constraints.

Table of ~~$126.9 million, subject to post-closing adjustments, bringing~~Contents

Given the dynamic nature of the events described above, we cannot reasonably estimate the period of time that the COVID-19 pandemic, the depressed commodity prices and the adverse macroeconomic will persist, the full extent of the impact they will have on our ~~total mineral interests to 15,870 net royalty acres as~~industry and our business, financial condition or cash flows, or the pace or extent of ~~June 30, 2019.~~ any subsequent recovery.

Acquisitions Update

We ~~funded our~~did not complete any acquisitions during the second quarter of ~~2019 with cash on hand, a portion~~2020, leaving our footprint of ~~the net proceeds from our February 2019 equity offering and borrowings under our revolving credit facility.~~

~~Pending Drop-Down and Anticipated Increase in the Borrowing Base under the Operating Company’s Revolving Credit Facility~~

~~Subsequent to the end of the second quarter of 2019, we entered into a definitive purchase agreement to acquire certain~~ mineral and royalty interests ~~from subsidiaries~~at a total of ~~Diamondback for 18.3 million~~24,714 royalty acres.

Cash Distribution Update

On July 29, 2020, the board of directors of our ~~newly-issued Class B units, 18.3 million newly-issued units of the Operating Company and $150.0 million in~~general partner declared a cash ~~subject to certain adjustments, which we refer to herein as the Pending Drop-Down. Based on the volume weighted average sales price of our common units~~distribution for the 10-trading day period ending July 26, 2019 of $30.07, the transaction is valued at $700.0 million. The mineral and royalty interests being acquired in the Pending Drop-Down represent approximately 5,090 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by Diamondback, and have an average net royalty interest of approximately 3.2%. After giving pro forma effect to the Pending Drop-Down, our mineral interests atthree months ended June 30, ~~2019 would have totaled 20,960 net royalty acres. We anticipate closing~~2020 of $0.03 per common unit. The distribution is payable on August 20, 2020 to eligible common unitholders of record at the ~~Pending Drop-Down during the fourth quarter~~close of ~~2019. However, the Pending Drop-Down remains subject to completion of due diligence and satisfaction of other closing conditions. There can be no assurance that we will complete the Pending Drop-Down~~business on the terms contemplated in this report or at all. We intend to finance the cash portion of the purchase price of the Pending Drop-Down through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility.August 13, 2020.

Upon closing of the Pending Drop-Down, we anticipate that the borrowing base under the Operating Company’s revolving credit facility will be increased by $125.0 million to $725.0 million from $600.0 million at June 30, 2019.

Production and Operational Update

~~Our average daily production~~During the second quarter of 2020, there was limited completion activity on our mineral and royalty acreage as our operators reacted quickly to oil price volatility by cutting capital expenditures and mostly ceasing completion activity. As a result, during the second quarter of ~~2019 was 19,597 BOE/d (67% oil)~~2020, we estimate that 134 gross (2.4 net 100% royalty interest) horizontal wells, in which we have an average royalty interest of 1.8% were turned to production on our existing acreage position with an average lateral length of 8,648 feet. Of these 134 gross wells, Diamondback is the operator of 14, in which we have an average royalty interest of 8.4%, and ~~our operators received~~the remaining 120 gross wells, in which we have an average royalty interest of ~~$54.81 per Bbl~~1.1%, are operated by third parties.

Despite the continued depressed commodity price environment, there continues to be active development across our asset base, as there are currently 14 gross rigs operating on our mineral and royalty acreage, four of which are operated by Diamondback. Although visibility into third-party operators’ anticipated activity levels has increased in recent months, it remains limited and near-term activity is expected to be driven primarily by Diamondback operations. Diamondback has recently brought three completion crews back to work after taking an almost three-month break from all completion activity in the second quarter of 2020. During the second half of 2020, Diamondback expects to focus its completion activity on areas where we have significant mineral ownership, which we anticipate will allow our oil ~~$18.33 per Bbl~~production to grow sequentially through the end of ~~natural gas liquids~~2020. This activity should lead to strong fourth quarter 2020 exit rate production and ~~$(0.65) per Mcf~~demonstrates the differentiated relationship between us and Diamondback as compared to our mineral royalty peers and their operators.

Table of ~~natural gas,~~Contents

The following table summarizes our gross well information as of July 14, 2020:


	As of July 14, 2020
	Diamondback Operated		Third Party Operated		Total
Horizontal wells turned to production:
Gross wells	14		120		134
Net 100% royalty interest wells	1.2		1.3		2.4
Average percent net royalty interest	8.4	%	1.1	%	1.8	%

Horizontal producing well count:
Gross wells	1,079		3,401		4,480
Net 100% royalty interest wells	84.4		51.8		136.2
Average percent net royalty interest	7.8	%	1.5	%	3.0	%


Horizontal active development well count⁽¹⁾:
Gross wells	66		419		485
Net 100% royalty interest wells	5.2		2.9		8.1
Average percent net royalty interest	7.9	%	0.7	%	1.7	%

Line of sight wells⁽²⁾:
Gross wells	74		366		440
Net 100% royalty interest wells	4.3		4.5		8.8
Average percent net royalty interest	5.8	%	1.2	%	2.0	%

(1) The total 485 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.

(2) The total 440 line-of-sight wells are those that are not currently in the process of active development, but for anwhich Viper has 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 current depressed oil prices.

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Results of Operations

The following table summarizes our revenue and expenses and production data for the periods indicated:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(In thousands)
Operating Results:
Operating income:
Royalty income	$	32,444	$	70,442	$	109,273	$	130,870
Lease bonus income	23		1,749		1,645		2,909

Other operating income	202		3		443		5
Total operating income	32,669		72,194		111,361		133,784
Costs and expenses:
Production and ad valorem taxes	3,110		4,389		9,257		8,081

Depletion	22,782		16,512		47,424		32,711

General and administrative expenses	1,683		1,723		4,349		3,418

Total costs and expenses	27,575		22,624		61,030		44,210
Income from operations	5,094		49,570		50,331		89,574
Other income (expense):
Interest expense, net	(7,669)		(2,713)		(16,632)		(7,262)


Loss on derivative instruments, net	(34,443)		—		(42,385)		—
Gain (loss) on revaluation of investment	3,443		50		(6,677)		3,642
Other income, net	519		547		923		1,203
Total other expense, net	(38,150)		(2,116)		(64,771)		(2,417)
(Loss) income before income taxes	(33,056)		47,454		(14,440)		87,157
Provision for (benefit from) income taxes	—		180		142,466		(34,428)
Net (loss) income	(33,056)		47,274		(156,906)		121,585
Net (loss) income attributable to non-controlling interest	(11,304)		45,009		7,015		85,541
Net (loss) income attributable to Viper Energy Partners LP	$	(21,752)	$	2,265	$	(163,921)	$	36,044

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	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019

Production Data:
Oil (MBbls)	1,315		1,202		2,902		2,349
Natural gas (MMcf)	2,685		1,640		5,344		3,512
Natural gas liquids (MBbls)	467		308		947		563
Combined volumes (MBOE)	2,230		1,783		4,740		3,497

Average daily oil volumes (BO/d)	14,453		13,205		15,947		12,978
Average daily combined volumes (BOE/d)	24,508		19,597		26,041		19,321


Average sales prices:
Oil ($/Bbl)	$	21.00	$	54.81	$	34.39	$	50.17
Natural gas ($/Mcf)⁽¹⁾	$	0.46	$	(0.65)	$	0.30	$	0.79
Natural gas liquids ($/Bbl)	$	7.69	$	18.33	$	8.32	$	18.22
Combined ($/BOE)	$	14.55	$	39.50	$	23.06	$	37.42

Oil, hedged ($/Bbl)⁽²⁾	$	22.39	$	54.81	$	35.03	$	50.17
Natural gas, hedged ($/Mcf)⁽²⁾	$	(1.01)	$	(0.65)	$	(0.53)	$	0.79
Natural gas liquids ($/Bbl)⁽²⁾	$	7.69	$	18.33	$	8.32	$	18.22
Combined price, hedged ($/BOE)⁽²⁾	$	13.60	$	39.50	$	22.52	$	37.42

Average costs ($/BOE):
Production and ad valorem taxes	$	1.39	$	2.46	$	1.95	$	2.31

General and administrative - cash component	0.63		0.70		0.78		0.73
Total operating expense - cash	$	2.02	$	3.16	$	2.73	$	3.04

General and administrative - non-cash component	$	0.13	$	0.26	$	0.14	$	0.25
Interest expense, net	$	3.44	$	1.52	$	3.51	$	2.08
Depletion	$	10.21	$	9.26	$	10.01	$	9.35

(1)The average realized price of ~~$39.50 per BOE. The average realized price of $(0.65) per Mcf of~~ natural gas was ~~primarily due to~~calculated in accordance with the pricing terms under our operators’ natural gas delivery contracts, which are generally tied to the NYMEX price quoted at Henry Hub. Actual volumetric prices realized from the sale of natural gas, however, differ from the quoted NYMEX price as a result of quality and location differentials. During the second quarter of 2020, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of ~~$(1.68)~~$(0.48) relative to the NYMEX price quoted at Henry Hub. Our operators may have varying terms under which they sell their natural gas, but we are ~~mostly~~primarily impacted by location differences resulting from supply and demand imbalances and limited takeaway capacity within the Permian Basin.

~~During~~(2)Hedged prices reflect the ~~second quarter~~impact of ~~2019, we estimate that 198 gross (4.1 net 100% royalty interest) horizontal wells with an average royalty interest of 2.1% were turned to production~~cash settlements on our existing acreage position with an average lateral length of 8,849 feet. Of these 198 gross wells, Diamondback is the operator of 54 with an average royalty interest of 2.8%, and the remaining 144 gross wells, which have an average royalty interest of 1.8%, are operated by third parties. Additionally, during the second quarter of 2019, we acquired 401 net royalty acres for an aggregate purchase price of approximately $44.2 million, which added a further 18 gross (0.2 net 100% royalty interest) producing horizontal wells with an average royalty interest of 1.3%. In total, as of June 30, 2019, we had 1,212 vertical wells and 2,889 horizontal wells producingmatured commodity derivative transactions on our ~~acreage. There continues~~average sales prices. We did not have any derivative contracts prior to ~~be active development on our mineral acreage as represented by approximately 377 gross horizontal wells currently in the process~~February of active development, in which we expect to own an average 2.2% net royalty interest (8.4 net 100% royalty interest). These wells currently in the process of active development include various wells currently being drilled by the 55 active rigs which were on our acreage as of July 9, 2019, in addition to other wells currently waiting to be completed, actively in the process of being completed or waiting to be turned to production. Additionally, 385 active drilling permits have been filed on our acreage in the past six months, in which we expect to own an average 2.2% net royalty interest (8.3 net 100% royalty interest). In July 2019, Diamondback has already turned to production ten wells in Spanish Trail in which we have an average royalty interest of 22%, which should drive strong organic growth in the second half of the year. An additional five wells in Spanish Trail are expected to be brought online in the fourth quarter of 2019, in each of which we have a 25% net royalty interest.2020.

~~We declared a cash dividend for the second quarter of 2019 of $0.47 per common unit, payable on August 21, 2019, to unitholders of record at the close of business on August 14, 2019.~~

Table of Contents

~~Recapitalization, Tax Status Election and Related Transactions~~

In March 2018, we announced that the Board of Directors of our general partner unanimously approved a change of our federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 we (i) amended and restated our First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, or Operating Company, (iii) amended and restated our existing registration rights agreement with Diamondback and (iv) entered into an exchange agreement with Diamondback, our general partner and the Operating Company. Simultaneously with the effectiveness of these agreements, Diamondback delivered and assigned to us the 73,150,000 common units Diamondback owned in exchange for (i) 73,150,000 of our newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018, or Recapitalization Agreement. Immediately following that exchange, we continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and Diamondback owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of our July 2018 offering of units, we owned approximately 41% of the outstanding units issued by the Operating Company and Diamondback owned the remaining approximately 59%. The Operating Company units and our Class B units 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).

On May 10, 2018, the change in our income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to us in respect of its general partner interest and (ii) Diamondback made a cash capital contribution of $1.0 million to us in respect of the Class B units. Diamondback, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, Diamondback also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 of our common units and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of our Class B units. The General Partner continues to serve as our general partner and Diamondback continues to control us. After the effectiveness of the tax status election and the completion of related transactions, our minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to our business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to our Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and our Current Report on Form 8-K filed with the SEC on May 15, 2018.

~~Principal Components of Our Cost Structure~~

~~Production and Ad Valorem Taxes~~

Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established 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 natural gas interests.

~~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.

~~Depletion~~

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 depletion.

~~Table of Contents~~

~~Income Tax Expense~~

Prior to our change in federal income tax status, we were organized as a pass-through entity for income tax purposes. As a result, our partners were responsible for federal income taxes on their share of our taxable income. Subsequent to the Partnership’s change in tax status, we are subject to federal income taxes at the U.S. corporate statutory rate. The Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items.

We are subject to the Texas margin tax. For the three months ended June 30, 2019 and 2018, we accrued less than $0.1 million and $0.2 million, respectively, and for the six months ended June 30, 2019 and 2018, we accrued $0.1 million and $0.2 million, respectively, for Texas margin tax payable pursuant to our tax sharing agreement with Diamondback.

~~Results of Operations~~

~~The following table summarizes our revenue and expenses and production data for the periods indicated:~~

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 2019 2018
(in thousands)
Operating Results:
Operating income:
Royalty income $ 70,442
$ 74,277
$ 130,870
$ 136,405
Lease bonus income 1,749
928
2,909
928
Other operating income 3
58
5
108
Total operating income 72,194
75,263
133,784
137,441
Costs and expenses:
Production and ad valorem taxes 4,389
4,867
8,081
9,106
Depletion 16,512
13,260
32,711
24,785
General and administrative expenses 1,723
2,210
3,418
4,921
Total costs and expenses 22,624
20,337
44,210
38,812
Income from operations 49,570
54,926
89,574
98,629
Other income (expense):
Interest expense, net (2,713 ) (3,252 ) (7,262 ) (5,350 )
Gain on revaluation of investment 50
4,465
3,642
5,364
Other income, net 547
447
1,203
839
Total other income (expense), net (2,116 ) 1,660
(2,417 ) 853
Income before income taxes 47,454
56,586
87,157
99,482
Provision for (benefit from) income taxes 180
(71,878 ) (34,428 ) (71,878 )
Net income 47,274
128,464

121,585
171,360
Net income attributable to non-controlling interest 45,009
29,060
85,541
29,060
Net income attributable to Viper Energy Partners LP $ 2,265
$ 99,404

$ 36,044
$ 142,300

~~Table of Contents~~

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 2019 2018

Production Data:
Oil (MBbls) 1,202
1,052
2,349
1,958
Natural gas (MMcf) 1,640
1,280
3,512
2,442
Natural gas liquids (MBbls) 308
221
563
391
Combined volumes (MBOE) 1,783
1,485
3,497
2,756
Daily combined volumes (BOE/d) 19,597
16,323
19,321
15,228
% Oil 67 % 71 % 67 % 71 %

Average sales prices:
Oil ($/Bbl) $ 54.81
$ 62.61
$ 50.17
$ 62.03
Natural gas ($/Mcf)⁽¹⁾
$ (0.65 ) $ 2.03
$ 0.79
$ 2.08
Natural gas liquids ($/Bbl) $ 18.33
$ 26.48
$ 18.22
$ 25.22
Combined ($/BOE) $ 39.50
$ 50.01
$ 37.42
$ 49.49

Average Costs ($/BOE):
Production and ad valorem taxes $ 2.46
$ 3.28
$ 2.31
$ 3.30
General and administrative - cash component 0.70
1.18
0.73
1.15
Total operating expense - cash $ 3.16
$ 4.46
$ 3.04
$ 4.45

General and administrative - non-cash component $ 0.26
$ 0.31
$ 0.25
$ 0.64
Interest expense, net $ 1.52
$ 2.19
$ 2.08
$ 1.94
Depletion $ 9.26
$ 8.93
$ 9.35
$ 8.99

~~(1)~~

The average realized price of $(0.65) per Mcf of natural gas was primarily due to the pricing terms under our operators’ natural gas delivery contracts, which are generally tied to NYMEX price quoted at Henry Hub. Actual volumetric prices realized from the sale of natural gas, however, differ from the quoted NYMEX price as a result of quality and location differentials. During the second quarter, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(1.68) relative to the NYMEX price quoted at Henry Hub. Our operators may have varying terms under which they sell their natural gas, but we are mostly impacted by location differences resulting from supply and demand imbalances and limited takeaway capacity within the Permian Basin.

Comparison of the Three Months Ended June 30, ~~2019~~2020 and ~~2018~~2019

Royalty Income

~~Our royalty income for the three months ended June 30, 2019 and 2018 was $70.4 million and $74.3 million, respectively.~~ Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes.

The following table presents the impact of pricing and production changes on our royalty income for the three months ended June 30, 2020 and 2019:


	Change in prices		Production volumes⁽¹⁾		Total net dollar effect of change
					(In thousands)
Effect of changes in price:
Oil	$	(33.81)	1,315		$	(44,473)
Natural gas	$	1.11	2,685		2,993
Natural gas liquids	$	(10.64)	467		(4,975)
Total income due to change in price					$	(46,455)

	Change in production volumes⁽¹⁾		Prior period average prices		Total net dollar effect of change
					(In thousands)
Effect of changes in production volumes:
Oil	113		$	54.81	$	6,227
Natural gas	1,045		$	(0.65)	(685)
Natural gas liquids	159		$	18.33	2,915
Total income due to change in production volumes					8,457
Total change in income					$	(37,998)

(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

~~Table~~The impact of ~~Contents~~

~~The~~the decrease in average prices received during the three months ended June 30, ~~2019~~2020 as compared to the three months ended June 30, ~~2018,~~2019 was partially offset by a ~~20%~~25% increase in combined volumes sold by our operators as compared to the three months ended June 30, ~~2018.~~2019.

Table of Contents

Change in prices
Production volumes⁽¹⁾
Total net dollar effect of change
(in thousands)
Effect of changes in price:
Oil $ (7.80 ) 1,202
$ (9,370 )
Natural gas $ (2.69 ) 1,640
(4,409 )
Natural gas liquids $ (8.15 ) 308
(2,513 )
Total income due to change in price $ (16,292 )

Change in production volumes⁽¹⁾
Prior period average prices Total net dollar effect of change
(in thousands)
Effect of changes in production volumes:
Oil 150
$ 62.61
$ 9,397
Natural gas 360
$ 2.03
732
Natural gas liquids 88
$ 26.48
2,328
Total income due to change in production volumes 12,457
Total change in income $ (3,835 )


~~(1)~~	Production ~~volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.~~

~~Realized pricing improved in the second quarter of 2019 compared to the first quarter of 2019 as some of Diamondback’s fixed differential contracts began to roll off~~ and convert to commitments on new-build long-haul pipelines and others moved closer to current Midland market price. Based on current market differentials and estimated in-basin gathering cost, we continue to expect to realize approximately 88% to 92% of WTI in the future remainder of 2019 and approximately 100% of WTI in 2020.

Ad Valorem Taxes

~~Lease Bonus Income~~

The following table presents the production and ad valorem taxes for the three months ended June 30, 2020 and 2019:

~~Lease bonus~~


	Three Months Ended June 30,
	2020										2019
	Amount (in thousands)		Per BOE		Percentage of Royalty Income		Amount (in thousands)		Per BOE		Percentage of Royalty Income
Production taxes	$	1,692	$	0.76	5.2	%	$	3,208	$	1.80	4.6	%
Ad valorem taxes	1,418		0.63		4.4		1,181		0.66		1.7
Total production and ad valorem taxes	$	3,110	$	1.39	9.6	%	$	4,389	$	2.46	6.3	%

Production taxes as a percentage of royalty income ~~increased by $0.8 million~~ for the three months ended June 30, ~~2019 as~~2020 compared to ~~the three months ended June 30, 2018. During the~~ three months ended June 30, 2019 ~~we received $39,000 in lease bonus payments~~increased primarily due to ~~extend the term~~prior period accrual adjustments. Ad valorem taxes as a percentage of one lease, reflecting an average bonus of $1,800 per acre and $1.7 million for four new leases, reflecting an average bonus of $13,632 per acre. During the three months ended June 30, 2018, we received $0.9 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $6,111 per acre.

~~Table of Contents~~

~~Production and Ad Valorem Taxes~~

~~Production taxes per unit of production~~royalty income for the three months ended June 30, ~~2019 and 2018 were $1.80 and $2.36, respectively. The decrease in production taxes per unit of production during the~~2020 compared to three months ended June 30, 2019 ~~was primarily~~increased due to a ~~20% increase~~decrease in ~~production volumes,~~sales revenues as compared to a 5% decrease in revenue year over year. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities, while ad valorem taxes are generally based on the valuation of our oil and natural gas interests. Ad valorem taxes per unit of production for the three months ended June 30, 2019 and 2018 were $0.66 and $0.92, respectively. The decreasean increase in ad valorem taxes ~~per unit of production during the three months ended June 30, 2019 was primarily due to a higher percentage increase in production volumes as compared to the~~caused by an increase in the valuation of oil and natural gas interests ~~year~~quarter over ~~year.~~quarter primarily due to acquisitions and drilling activity.

Three Months Ended June 30,
2019 2018
Amount Per BOE Amount Per BOE
Production taxes $ 3,208
$ 1.80
$ 3,504
$ 2.36
Ad valorem taxes 1,181
0.66 1,363
0.92
Total production and ad valorem taxes $ 4,389
$ 2.46
$ 4,867
$ 3.28

Depletion

~~Depletion~~The $6.3 million, or 38%, increase in depletion expense ~~increased by $3.3 million~~for the three months ended June 30, 2020 compared to ~~$16.5 million~~the same period in 2019 was due primarily to an increase in the depletion rate to $10.21 for the three months ended June 30, 2020 compared to $9.26 for the three months ended June 30, 2019, ~~from $13.3 million for the three months ended June 30, 2018. The increase~~which largely resulted ~~primarily~~ from higher production levels and an increase in net book value on new reserves ~~added.~~

~~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 June 30, 2019 and 2018, we incurred general and administrative expenses of $1.7 million and $2.2 million, respectively. The decrease of $0.5 million during the three months ended June 30, 2019 was primarily due to higher legal expenses in 2018 relatedadded to the ~~change in tax structure that took place in March 2018 coupled with a slight decrease in unit-based compensation expense.~~depletion base.

Net Interest Expense

~~The net interest expense for the three months ended June 30, 2019 and 2018 reflects the interest incurred under our credit agreement.~~ Net interest expense for the three months ended June 30, 2020 and 2019 ~~and 2018~~ was ~~$2.7~~$7.7 million and ~~$3.3~~$2.7 million, respectively. The ~~decrease~~increase of ~~approximately $0.5~~$5.0 million in net interest expense for three months ended June 30, 2020 as compared to 2019 was due primarily to ~~decreased borrowings partially offset by~~additional interest incurred on the Notes which were issued in October 2019.

Derivative Instruments

We recorded a ~~higher average interest rate~~loss on derivative instruments for the three months ended June 30, 2020 of $34.4 million, which includes cash payments of $2.1 million on settlements of commodity derivative contracts during the period. We had no derivative instruments during the three months ended June 30, ~~2019~~2019. We are required to recognize all derivative instruments on our balance sheet as ~~compared~~either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the ~~three months ended June 30, 2018.~~

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

~~We recorded an income tax expense of $0.2 million~~cash and ~~an income tax benefit of $71.9 million for the three months ended June 30, 2019 and 2018, respectively. The change~~non-cash changes in fair value on derivative instruments in our ~~income tax provision was primarily due to deferred benefit recognized during~~consolidated statements of operations under the ~~three months ended June 30, 2018 as a result~~line item captioned “Loss on derivative instruments, net.”

Table of our change in federal income tax status. Total income tax benefit for the three months ended June 30, 2019 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest.

Contents

Comparison of the Six Months Ended June 30, ~~2019~~2020 and ~~2018~~2019

Royalty Income

~~Our royalty income for the six months ended June 30, 2019 and 2018 was $130.9 million and $136.4 million, respectively.~~ Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes.

~~Table~~The following table presents the impact of ~~Contents~~pricing and production changes on our royalty income for thesix months ended June 30, 2020 and 2019:


	Change in prices		Production volumes⁽¹⁾		Total net dollar effect of change
					(In thousands)
Effect of changes in price:
Oil	$	(15.78)	2,902		$	(45,789)
Natural gas	$	(0.49)	5,344		(2,630)
Natural gas liquids	$	(9.90)	947		(9,370)
Total income due to change in price					$	(57,789)

	Change in production volumes(1)		Prior period average prices		Total net dollar effect of change
					(In thousands)
Effect of changes in production volumes:
Oil	553		$	50.17	$	27,756
Natural gas	1,832		$	0.79	1,443
Natural gas liquids	384		$	18.22	6,993
Total income due to change in production volumes					36,192
Total change in income					$	(21,597)

(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

The impact of the decrease in average prices received during the six months ended June 30, ~~2019~~2020 as compared to the six months ended June 30, ~~2018,~~2019 was partially offset by a ~~27%~~36% increase in combined volumes sold by our operators as compared to the six months ended June 30, ~~2018.~~2019.

Table of Contents

Change in prices Production volumes(1) Total net dollar effect of change
(in thousands)
Effect of changes in price:
Oil $ (11.86 ) 2,349
$ (27,855 )
Natural gas $ (1.30 ) 3,512
(4,555 )
Natural gas liquids $ (6.99 ) 563
(3,936 )
Total income due to change in price $ (36,346 )

Change in production volumes(1) Prior period average prices Total net dollar effect of change
(in thousands)
Effect of changes in production volumes:
Oil 391
$ 62.03
$ 24,257
Natural gas 1,069
$ 2.08
2,229
Natural gas liquids 172
$ 25.22
4,325
Total income due to change in production volumes 30,811
Total change in income $ (5,535 )


~~(1)~~	~~Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.~~

Production and Ad Valorem Taxes

~~Lease Bonus Income~~

The following table presents the production and ad valorem taxes for the six months ended June 30, 2020 and 2019:

~~Lease bonus~~


	Six Months Ended June 30,
	2020										2019
	Amount (in thousands)		Per BOE		Percentage of Royalty Income		Amount (in thousands)		Per BOE		Percentage of Royalty Income
Production taxes	$	5,267	$	1.11	4.8	%	$	6,216	$	1.78	4.7	%
Ad valorem taxes	3,990		0.84		3.7	%	1,865		0.53		1.4	%
Total production and ad valorem taxes	$	9,257	$	1.95	8.5	%	$	8,081	$	2.31	6.1	%

Production taxes as a percentage of royalty income ~~increased by $2.0 million~~ for the six months ended June 30, ~~2019 as~~2020 compared to the six months ended June 30, ~~2018. During the six months ended June 30,~~ 2019 ~~we received less than $0.1 million in lease bonus payments to extend the term~~remained relatively flat. Ad valorem taxes as a percentage of six leases, reflecting an average bonus of $754 per acre and $2.8 million for ten new leases, reflecting an average bonus of $14,689 per acre. During the six months ended June 30, 2018, we received $0.9 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $6,111 per acre.

~~Table of Contents~~

~~Production and Ad Valorem Taxes~~

~~Production taxes per unit of production~~royalty income for the six months ended June 30, ~~2019 and 2018 were $1.78 and $2.37, respectively. The decrease in production taxes per unit of production during the~~2020 compared to six months ended June 30, 2019 ~~was primarily~~increased due to a ~~27% increase~~decrease in ~~production volumes,~~sales revenues as compared to a 4% decrease in revenue year over year. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities, while ad valorem taxes are generally based on the valuation of our oil and natural gas interests. Ad valorem taxes per unit of production for the six months ended June 30, 2019 and 2018 were $0.53 and $0.93, respectively. The decreasean increase in ad valorem taxes ~~per production unit during the six months ended June 30, 2019 was primarily due to a higher percentage increase in production volumes as compared to the~~caused by an increase in the valuation of oil and natural gas interests year over ~~year.~~year primarily due to acquisitions and drilling activity.

Six Months Ended June 30,
2019 2018
Amount Per BOE Amount Per BOE
Production taxes $ 6,216
$ 1.78
$ 6,545
$ 2.37
Ad valorem taxes 1,865
0.53 2,561
0.93
Total production and ad valorem taxes $ 8,081
$ 2.31
$ 9,106
$ 3.30

Depletion

~~Depletion~~The $14.7 million, or 45%, increase in depletion expense ~~increased by $7.9 million~~for the six months ended June 30, 2020 compared to ~~$32.7 million~~the same period in 2019 was due primarily to an increase in the depletion rate to $10.01 for the six months ended June 30, 2020 compared to $9.35 for the six months ended June 30, 2019, ~~from $24.8 million for the six months ended June 30, 2018. The increase~~which largely resulted ~~primarily~~ from higher production levels and an increase in net book value on new reserves ~~added.~~added to the depletion base.

General and Administrative Expenses

~~The general~~General and administrative expenses primarily reflect costs associated with us being a publicly traded limited partnership, ~~unit-based~~unit-based compensation and ~~the~~ amounts reimbursed to our general partner under our partnership agreement. For the six months ended June 30, ~~2019~~2020 and ~~2018,~~2019, we incurred general and administrative expenses of ~~$3.4~~$4.3 million and ~~$4.9~~$3.4 million, respectively. The ~~decrease~~increase of ~~$1.5~~$0.9 million during the six months ended June 30, ~~2019~~2020 was primarily due to increases in amounts allocated from our general partner under our partnership agreement, higher software license fees, bad debt expense and higher legal expenses in ~~2018 related to the change~~2020. These increases were partially offset by decreases in partnership tax ~~structure that took place in March 2018 coupled with a slight decrease in~~compliance and K-1 preparation fees and unit-based ~~compensation expense.~~compensation.

Net Interest Expense

~~The net interest expense for the six months ended June 30, 2019 and 2018 reflects the interest incurred under our credit agreement.~~ Net interest expense for the six months ended June 30, 2020 and 2019 ~~and 2018~~ was ~~$7.3~~$16.6 million and ~~$5.4~~$7.3 million, respectively. The increase of ~~$1.9~~$9.3 million was due to increased borrowings and a higher interest rate during the six months ended June 30, ~~2019~~2020 as compared to the six months ended June 30, ~~2018.~~2019, as a result of issuing the Notes during the fourth quarter of 2019. This increase was partially offset by repayments of the borrowings under the Operating Company’s revolving credit facility.

~~Benefit from~~Derivative Instruments

We recorded a loss on derivative instruments for the six months ended June 30, 2020 of $42.4 million, which includes cash payments of $2.6 million on settlements of commodity derivative contracts during the period. We had no derivative instruments during the six months ended June 30, 2019. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Loss on derivative instruments, net.”

Table of Contents

Provision for (Benefit from) Income Taxes

We recorded an income tax expense of $142.5 million and income tax benefit of $34.4 ~~million and $71.9~~ million for the six months ended June 30, ~~2019~~2020 and ~~2018,~~2019, respectively. The change in our income tax provision was ~~primarily~~primarily due to the application of a valuation allowance on our deferred ~~benefit recognized~~tax assets during the six months ended June 30, ~~2018~~2020, and the revision during the six months ended June 30, 2019 of estimated deferred taxes recognized as a result of our change in federal income tax status. ~~Prior to the second quarter of 2018, we had no provision for or benefit from income taxes. Total~~The total income tax ~~benefit~~provision for the six months ended June 30, ~~2019~~2020 differed from amounts ~~computed~~computed by applying the federal statutory tax rate to pre-tax ~~income~~loss for the period primarily due to ~~the revision~~impact of ~~estimated~~recording a valuation allowance on our deferred ~~taxes recognized as a result of the Partnership’s change in~~ tax ~~status~~assets and net income attributable to the non-controlling interest. See Note 9—Income Taxes for further details.

Non-GAAP Financial Measures

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 common unitholders.

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We define Adjusted EBITDA as net (loss) income plus interest expense, net, non-cash unit-based compensation expense, depletion expense, (loss) gain on revaluation of investment, non-cash loss on derivative instruments, gain on extinguishment of debt and provision for (benefit from) income taxes. Adjusted EBITDA is not a measure of net (loss) income as determined by GAAP. We exclude the items listed above from net (loss) income 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 (loss) income, our most directly comparable GAAP financial measure for the periods indicated:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
	(In thousands)
Net (loss) income	$	(33,056)	$	47,274	$	(156,906)	$	121,585
Interest expense, net	7,669		2,713		16,632		7,262

Non-cash unit-based compensation expense	283		472		670		877
Depletion	22,782		16,512		47,424		32,711

(Gain) loss on revaluation of investment	(3,443)		(50)		6,677		(3,642)
Non-cash loss on derivative instruments, net	32,342		—		39,831		—
Gain on extinguishment of debt	(14)		—		(14)		—
Provision for (benefit from) income taxes	—		180		142,466		(34,428)
Consolidated Adjusted EBITDA	26,563		67,101		96,780		124,365
Less: Adjusted EBITDA attributable to non-controlling interest	15,198		35,983		55,373		66,691
Adjusted EBITDA attributable to Viper Energy Partners LP	$	11,365	$	31,118	$	41,407	$	57,674

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 2019 2018
(In thousands)
Net income $ 47,274
$ 128,464
$ 121,585
$ 171,360
Interest expense, net 2,713
3,252
7,262
5,350
Non-cash unit-based compensation expense 472
452
877
1,740
Depletion 16,512
13,260
32,711
24,785
Gain on revaluation of investment (50 ) (4,465 ) (3,642 ) (5,364 )
Provision for (benefit from) income taxes 180
(71,878 ) (34,428 ) (71,878 )
Consolidated Adjusted EBITDA 67,101
69,085
124,365
125,993
EBITDA attributable to non-controlling interest (35,983 ) (43,642 ) (66,691 ) (43,642 )
Adjusted EBITDA attributable to Viper Energy Partners LP $ 31,118
$ 25,443
$ 57,674
$ 82,351

~~Non-GAAP Financial Measures~~

~~Gross oil, natural gas, and natural gas liquids sales and net sales prices~~

Revenues and gathering and transportation expenses related to production are reported net in our financial statements under GAAP. This impacts the comparability of prior periods and certain operating metrics, such as per-unit sales prices, as those metrics are prepared in accordance with GAAP using the net presentation for some revenues and the gross presentation for other metrics, and those periods prior to the fourth quarter of 2018. In order to provide metrics consistent with management’s assessment of our operating results, we have presented both net (GAAP) and gross (non-GAAP) oil, natural gas, and natural gas liquid sales and the gross sales price. The gross sales price (non-GAAP), is calculated by using the net oil, natural gas, and natural liquid gas net revenues plus gathering and transportation expenses divided by the sales volumes. We believe presenting our gross revenues and sales prices allows for a useful comparison of net and gross sales prices for prior periods.

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~~The following table presents a reconciliation of net oil, natural gas and natural gas liquids sales (GAAP) to gross oil, natural gas and natural gas liquids sales (non-GAAP) for the periods indicated:~~

Three Months Ended June 30, 2019 Three Months Ended June 30, 2018
(in thousands) Oil Natural gas Natural gas liquids Total Oil Natural gas Natural gas liquids Total
Net oil, natural gas and natural gas liquids sales (GAAP) $ 65,863
$ (1,074 ) $ 5,653
$ 70,442
$ 65,836
$ 2,603
$ 5,838
$ 74,277
Plus: Gathering and transportation expenses 365
264
248
877
49
49
45
143
Gross oil natural gas and natural gas liquids sales (non-GAAP) 66,228
(810 ) 5,901
71,319
65,885
2,652
5,883
74,420
Sales volumes (MBbl/MMcf/MBoe) 1,202
1,640
308
1,783
1,052
1,280
221
1,485
Gross sales price (non-GAAP) $ 55.12
$ (0.49 ) $ 19.13
$ 39.99
$ 62.66
$ 2.07
$ 26.68
$ 50.10

Six Months Ended June 30, 2019 Six Months Ended June 30, 2018
(in thousands) Oil Natural gas Natural gas liquids Total Oil Natural gas Natural gas liquids Total
Net oil, natural gas and natural gas liquids sales (GAAP) $ 117,850
$ 2,765
$ 10,255
$ 130,870
$ 121,448
$ 5,091
$ 9,866
$ 136,405
Plus: Gathering and transportation expenses 599
569
497
1,665
126
137
145
408
Gross oil natural gas and natural gas liquids (non-GAAP) 118,449
3,334
10,752
132,535
121,574
5,228
10,011
136,813
Sales volumes (MBbl/MMcf/MBoe) 2,349
3,512
563
3,497
1,958
2,442
391
2,756
Gross sales price (non-GAAP) $ 50.42
$ 0.95
$ 19.10
$ 37.90
$ 62.09
$ 2.14
$ 25.59
$ 49.64

Liquidity and Capital Resources

Overview

Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings and borrowings under our credit ~~agreement, and our~~agreement. Our primary uses of cash have been, and are expected to continue to be, distributions to our unitholders and ~~replacement and growth~~ capital expenditures ~~including~~for the acquisition of our mineral interests and royalty interests in oil and natural gas ~~interests.~~properties. We intend to finance potential future acquisitions through a combination of cash on hand, borrowings under our credit agreement, issuance of common units to the sellers and, subject to market conditions and other factors, proceeds from one or more capital market transactions, which may include debt or equity offerings. Our ability to generate cash is subject to ~~a number of~~several factors, some of which are beyond our control, including commodity prices and general economic, financial, competitive, legislative, regulatory and other factors, including weather. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions, may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

~~Our partnership agreement does not require us to distribute any~~Cash Distributions

Beginning with the first quarter of ~~the cash we generate from operations. However,~~2020, the board of directors of our general partner ~~has adopted a~~revised the distribution policy pursuant to which the Operating Company ~~will distribute all~~now distributes 25% of the available cash it generates each quarter to its unitholders (including us), and pursuant to which we in turn ~~will~~ distribute all of the available cash we receive from the Operating Company to our common unitholders.

~~Cash distributions are made to~~ Our available cash, and the ~~common unitholders~~available cash of ~~record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for us and~~ the Operating Company, for each quarter is determined by the board of directors of our general partner following the end of such quarter. ~~Available~~The Operating Company’s available cash ~~for the Operating Company for each quarter will~~ generally ~~equal~~equals its Adjusted EBITDA ~~reduced~~ for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if ~~any, and our~~any. Our available cash ~~will~~for each quarter generally ~~equal~~equals our Adjusted EBITDA (which ~~will be~~is our ~~proportionate~~proportional share of the available

~~Table~~ cash of ~~Contents~~

~~cash distributed to us by~~ the Operating ~~Company)~~Company for the quarter), less ~~as a result of the Tax Election,~~ cash needed for the payment of income taxes ~~payable~~ by us, if ~~any.~~any, and the preferred distribution. Immediately prior to the adoption of this policy, the Operating Company’s policy was to distribute all of its available cash quarterly to its unitholders rather than 25%. The distribution policy was changed to enable the Operating Company to retain cash flow to help strengthen our balance sheet.

On July ~~28, 2019,~~29, 2020, the board of directors of ~~the General Partner~~our general partner approved a cash distribution for the second quarter of ~~2019~~2020 of ~~$0.47~~$0.03 per common unit, payable on August ~~21, 2019,~~20, 2020, to eligible unitholders of record at the close of business on August ~~14, 2019.~~13, 2020.

~~February~~ The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly or other basis.

2019 Equity Offering

In ~~February~~March 2019, we completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximately 54% of our total units then outstanding. We received net proceeds from this offering of approximately $340.6 million, after deducting underwriting discounts and commissions and estimated offering expenses. We used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under the Operating Company’s revolving credit facility and finance acquisitions during the period.

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Cash Flows

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


	Six Months Ended June 30,
	2020		2019

	(In thousands)
Cash Flow Data:
Net cash provided by operating activities	$	115,863	$	101,720
Net cash used in investing activities	(65,272)		(138,446)
Net cash (used in) provided by financing activities	(44,530)		26,854
Net increase (decrease) in cash	$	6,061	$	(9,872)

Six Months Ended June 30,
2019 2018

(in thousands)
Cash Flow Data:
Net cash flows provided by operating activities $ 101,720
$ 112,212
Net cash flows used in investing activities (138,446 ) (252,490 )
Net cash flows provided by financing activities 26,854
148,967
Net increase (decrease) in cash $ (9,872 ) $ 8,689

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 volume of oil and natural gas sold by our producers. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. The increase in net cash provided by operating activities during the six months ended June 30, 2020, was primarily due to changes in our working capital accounts, and most notably, in our accounts receivable. This increase was partially offset by a decrease in revenues as discussed in “—Results of Operations” above, and an increase in cash paid for interest on our debt due to the issuance of the Notes in the fourth quarter of 2019, for the six months ended June 30, 2020 compared to the six months ended June 30, 2019, respectively.

Investing Activities

Net cash used in investing activities ~~was $138.4 million and $252.5 million~~ during the six months ended June 30, 2020 and 2019, ~~and 2018, respectively, and~~was related to acquisitions of oil and natural gas interests and land.

Financing Activities

Net cash used in financing activities during the six months ended June 30, 2020, was primarily related to distributions of $87.3 million to our unitholders and by repurchases of the Notes totaling $13.8 million, net of discounts during the second quarter of 2020. These reductions were partially offset by net proceeds from borrowing activity under the Operating Company’s revolving credit facility of $57.0 million.

Net cash provided by financing activities ~~was $26.9 million~~ during the six months ended June 30, 2019, was primarily related to net proceeds from our public offering of common units of $340.6 million, partially offset by ~~repayments from~~ net ~~borrowing activity under our credit facility~~repayments of $198.5 million on borrowings under the Operating Company’s revolving credit facility and distributions of $114.7 million to our unitholders during the period. Net cash provided by financing activities was $149.0 million during the six months ended June 30, 2018, primarily related to proceeds from borrowings under our credit facility of $256.5 million, partially offset by distributions of $107.1 million to our unitholders during that period.

~~Our~~Indebtedness

The Operating Company’s Revolving Credit ~~Agreement~~Facility

On July ~~8, 2014,~~20, 2018, we, as guarantor, entered into ~~a secured revolving~~an amended and restated credit agreement ~~or revolving credit facility,~~ with the Operating Company, as borrower, Wells Fargo, as administrative agent, certain other lenders, and the Operating Company as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and we became a guarantor of the credit agreement. On July 20, 2018, we, the Operating Company, Wells Fargo and the other ~~lenders amended and restated the credit agreement to reflect the assumption by the Operating Company.~~lenders. The credit agreement, as amended ~~and restated,~~to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion, ~~and~~with a borrowing base ~~based on our oil and natural gas reserves and other factors (the “borrowing base”)~~ of ~~$600.0~~$580.0 million ~~subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing~~

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base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. Effective June 27, 2019, in connection with our spring 2019 redetermination, the borrowing base was increased from $555.0 million to $600.0 million and, as of June 30, ~~2019, we~~2020, and a maturity date of November 1, 2022. The Operating Company had ~~$212.5~~$153.5 million of outstanding borrowings and ~~$387.5~~$426.5 million available for future borrowings under this revolving credit facility. We intend to finance the cash portion of the purchase price of the Pending Drop-Down described in this report through a combination of cash on hand and borrowings under the Operating Company’s revolving credit ~~facility. Upon closing~~facility as of ~~the Pending Drop-Down, we anticipate that the borrowing base under the Operating Company’s revolving credit facility will be increased by $125.0 million to $725.0 million from $600.0 million at~~ June 30, ~~2019.~~2020. The next semi-annual redetermination is scheduled to occur in November 2020.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may 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 the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of our and our subsidiary’s assets.



~~Financial Covenant~~		~~Required Ratio~~
~~Ratio of total net debt to EBITDAX, as defined in the credit agreement~~		~~Not greater than 4.0 to 1.0~~
~~Ratio of current assets to liabilities, as defined in the credit agreement~~		~~Not less than 1.0 to 1.0~~

As of June 30, ~~2019,~~2020, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement. ~~The lenders may accelerate all~~

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Notes Offering

On October 16, 2019, we issued our 5.375% Senior Notes due 2027 in the aggregate principal amount of $500.0 million in a notes offering (which we refer to as the Notes Offering) under an indenture, dated as of October 16, 2019, among the Partnership, as issuer, the Operating Company, as guarantor and Wells Fargo Bank, National Association, as trustee, which we refer to as the Indenture. We received net proceeds of approximately $490.0 million from the Notes Offering. We loaned the gross proceeds of the ~~indebtedness under~~Notes Offering to the Operating ~~Company’s~~Company. The Operating Company used the proceeds from the Notes Offering to repay then outstanding borrowings under its revolving credit ~~facility upon~~facility. Interest on the ~~occurrence~~Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof from October 16, 2019, payable semi-annually on May 1 and ~~during~~November 1 of each year, commencing on May 1, 2020. The Notes will mature on November 1, 2027.

During the ~~continuance~~second quarter 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. With certain specified exceptions, the terms and provisions of our credit agreement generally may be amended with the consent of the lenders holding a majority2020, we repurchased $14.1 million of the outstanding ~~loans or commitments~~principal of the Notes at a cash price ranging from 97.5% to ~~lend.~~98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt. As of June 30, 2020, $485.9 million in aggregate principal amount of the Notes remained outstanding. After the second quarter of 2020, we repurchased $6.0 million of the principal outstanding of the Notes at a cash price of 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt. As of July 31, 2020, the remaining outstanding principal amount of Notes totaled $479.9 million.

Note 6—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q.

Contractual Obligations

~~There~~Other than the changes in our outstanding debt discussed in Note 6—Debt, and Note 13—Subsequent Events included in “Part I, Item 1—Consolidated Financial Statements” in this report, there were no material changes in our contractual obligations and other commitments as disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~2019.

Critical Accounting Policies

There have been no changes to our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~2019.

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Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

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 is~~prices are driven primarily by the prevailing worldwide price for crude oil and ~~spot market~~ prices ~~applicable to our~~for natural gas ~~production, as well as futures contract prices for~~in the United States. Both crude oil and natural gas ~~since our operators generally hedge a majority~~realized prices are also impacted by the quality of ~~their production.~~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 during~~and 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. Oil, natural gas liquids and natural gas prices have historically been volatile. Further, oil prices dropped sharply in early March 2020 and then continued to decline reaching negative levels. This was as a result of multiple factors affecting supply and demand in the global oil and gas markets, including actions taken by OPEC members and other exporting nations and impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic, which resulted in a widespread health and economic crisis. While OPEC members and certain other nations agreed in April of 2020 to cut production, which helped to reduce a portion of the excess supply in the market and improve oil prices, there is no assurance that this agreement will continue or be observed by its parties, and downward pressure on commodity prices has continued and could continue for the foreseeable future. We cannot predict if or when commodity prices will stabilize and at what levels.

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We use 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. With respect to our fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap or basis price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap or basis price. We have fixed price basis swaps for the spread between the Henry Hub natural gas price and the Waha Hub natural gas price.

At June 30, 2020, we had a net liability derivative position related to our commodity price derivatives of $39.8 million, related to our price swap, price basis swap derivatives and costless collars. We did not have any derivative contracts prior to February 2020. Utilizing actual derivative contractual volumes under our fixed price swaps as of June 30, 2020, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $46.2 million, an increase of $6.4 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position to $33.4 million, a decrease of $6.4 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 ~~several~~a limited number of significant purchasers and producers. For the six months ended June 30, 2019, three purchasers each accounted for more than 10% of our royalty income: Trafigura Trading LLC (31%), Concho Resources, Inc. (18%) and Shell Trading (US) Company (11%). For the six months ended June 30, 2018, two purchasers each accounted for more than 10% of our royalty income: Shell Trading (US) Company (46%) and RSP Permian LLC (20%). We do not require collateral and ~~do not believe~~ the ~~loss~~failure or inability of ~~any single~~our significant purchasers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. The ongoing COVID-19 pandemic, depressed commodity pricing environment and adverse 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 ~~our~~the Operating Company’s credit agreement. The terms of ~~our~~the credit agreement provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% in the case of the alternative base rate and from 1.75% to 2.75% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We entered into this credit agreement on July 8, 2014, as subsequently amended, and as of June 30, ~~2019,~~2020, we had ~~$212.5~~$153.5 million in outstanding borrowings. ~~Our~~During the three and six months ended June 30, 2020, the weighted average interest ~~rate~~rates on ~~borrowings under our~~the Operating Company’s revolving credit facility was 4.41%. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $2.1 million based on the $212.5 million outstanding in the aggregate under our credit agreement.were 2.41% and 2.82%, respectively.

ITEM 4. CONTROLS AND PROCEDURES

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

As of June 30, ~~2019,~~2020, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of the design and

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operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner have concluded that as of June 30, ~~2019,~~2020, 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 June 30, ~~2019~~2020 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Note 12—Commitments and Contingencies.

ITEM 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.

~~In addition~~As of the date of this filing, we continue to ~~the information set forth in this report, you should carefully consider~~be subject to the risk factors ~~discussed~~previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form ~~10–K~~10-K for the year ended December 31, ~~2018~~2019, filed with the SEC on February 18, 2020, and in ~~subsequent filings we make with the SEC. Except as disclosed in this report with respect to the Pending Drop-Down, there have been no material changes~~Part II, Item 1A. Risk Factors in our ~~risk factors from those described in our Annual~~Quarterly Report on Form ~~10–K~~10-Q for the ~~year~~quarterly period ended ~~December~~March 31, ~~2018.~~2020, filed with the SEC on May 8, 2020. Depending on the duration of the COVID-19 pandemic and its severity and related economic repercussions, however, the negative impact of many of the risks discussed in such reports may be heightened or exacerbated. For a discussion of the recent trends and uncertainties impacting our business, see also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—COVID-19 and Recent Collapse in Commodity Prices” and “—Production and Operational Update.”

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ITEM 6. EXHIBITS



Exhibit Number		Description
3.1		Certificate of Limited Partnership of Viper Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File ~~No.~~ 333-195769) filed on May 7, 2014).
3.2		Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 9, 2018 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.3		First Amendment to Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 10, 2018. (incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.4		Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of May 9, 2018. (incorporated by reference to Exhibit 3.3 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
~~4.1~~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).

4.1		Amended and Restated Registration Rights Agreement, dated as of May 9, 2018, by and between Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).





10.1		~~First~~Fifth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of ~~June 27, 2019,~~May 11, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the ~~lender~~lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on ~~July 3, 2019)~~May 15, 2020).
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*101		~~XBRL Instance Document.~~ The ~~instance document does not appear~~following financial information from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, formatted in ~~the interactive data file because its XBRL tags are embedded within the inline XBRL document.~~Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Unitholders’ Equity, (iv) 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.~~



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


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

Table of Contents

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

~~VIPER ENERGY PARTNERS LP~~

By:

~~By:~~

VIPER ENERGY PARTNERS GP LLC

its General Partner

Date:

~~July 31, 2019~~August 5, 2020

By:

/s/ Travis D. Stice

Travis D. Stice

Chief Executive Officer

Date:

~~July 31, 2019~~August 5, 2020

By:

/s/ Teresa L. Dick

Teresa L. Dick

Chief Financial Officer



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

PART I. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited)		��
~~Consolidated Balance Sheets~~	1
Consolidated Balance Sheets		1
Consolidated Statements of Operations		2
Consolidated Statements of Changes to Unitholders’ Equity		3
Consolidated Statements of Cash Flows		5
Condensed Notes to Consolidated Financial Statements		65

Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations		18

Item 3. Quantitative and Qualitative Disclosures about Market Risk		3130

Item 4. Controls and Procedures		31

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		32

Item 1A. Risk Factors		32

Item 6. Exhibits		33

Signatures		34



	Six Months Ended June 30,
	2019			2018
	(In thousands)
Cash flows from operating activities:
Net income	$	121,585		$	171,360
Adjustments to reconcile net income to net cash provided by operating activities:
Benefit from deferred income taxes	(34,536		)	(72,049		)
Depletion	32,711			24,785
Gain on revaluation of investment	(3,642		)	(5,364		)
Amortization of debt issuance costs	441			322
Non-cash unit-based compensation	877			1,740
Changes in operating assets and liabilities:
Royalty income receivable	(7,996		)	(5,329		)
Royalty income receivable—related party	(5,549		)	(2,995		)
Accounts payable and other accrued liabilities	(2,238		)	(440		)
Income tax payable	108			171
Other current assets	(41		)	11
Net cash provided by operating activities	101,720			112,212
Cash flows from investing activities:
Acquisition of oil and natural gas interests	(125,231		)	(253,056		)
Funds held in escrow	(13,215		)	—
Proceeds from sale of assets	—			441
Proceeds from the sale of investments	—			125
Net cash used in investing activities	(138,446		)	(252,490		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	171,000			256,500
Repayment on credit facility	(369,500		)	—
Debt issuance costs	(258		)	(440		)
Proceeds from public offerings	340,860			—
Public offering costs	(221		)	(2,034		)
Contributions by members	—			2,000
Units purchased for tax withholding	(353		)	—
Distributions to partners	(114,674		)	(107,059		)
Net cash provided by financing activities	26,854			148,967
Net increase (decrease) in cash	(9,872		)	8,689
Cash and cash equivalents at beginning of period	22,676			24,197
Cash and cash equivalents at end of period	$	12,804		$	32,886

Supplemental disclosure of cash flow information:
Interest paid	$	2,382		$	5,028



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2018	125,053		$	23.44
Granted	17,601		$	33.54
Vested	(60,133	)	$	21.38
Forfeited	(1,028	)	$	42.50
Unvested at June 30, 2019	81,493		$	26.91



	(in thousands)
Fair Value of investment as of December 31, 2017	$	33,851
Impact of adoption of Accounting Standards Update 2016-01	(18,651		)
Disposal of shares	(126		)
Gain on investment	5,364
Fair Value of investment as of June 30, 2018	$	20,438



	(in thousands)
Fair Value of investment as of December 31, 2018	$	14,525
Gain on investment	3,642
Fair Value of investment as of June 30, 2019	$	18,167



	Change in prices			Production volumes(1)		Total net dollar effect of change
						(in thousands)
Effect of changes in price:
Oil	$	(11.86	)	2,349		$	(27,855	)
Natural gas	$	(1.30	)	3,512		(4,555		)
Natural gas liquids	$	(6.99	)	563		(3,936		)
Total income due to change in price						$	(36,346	)

	Change in production volumes(1)			Prior period average prices		Total net dollar effect of change
						(in thousands)
Effect of changes in production volumes:
Oil	391			$	62.03	$	24,257
Natural gas	1,069			$	2.08	2,229
Natural gas liquids	172			$	25.22	4,325
Total income due to change in production volumes						30,811
Total change in income						$	(5,535	)



	Three Months Ended June 30, 2019									Three Months Ended June 30, 2018
(in thousands)	Oil		Natural gas			Natural gas liquids		Total		Oil		Natural gas		Natural gas liquids		Total
Net oil, natural gas and natural gas liquids sales (GAAP)	$	65,863	$	(1,074	)	$	5,653	$	70,442	$	65,836	$	2,603	$	5,838	$	74,277
Plus: Gathering and transportation expenses	365		264			248		877		49		49		45		143
Gross oil natural gas and natural gas liquids sales (non-GAAP)	66,228		(810		)	5,901		71,319		65,885		2,652		5,883		74,420
Sales volumes (MBbl/MMcf/MBoe)	1,202		1,640			308		1,783		1,052		1,280		221		1,485
Gross sales price (non-GAAP)	$	55.12	$	(0.49	)	$	19.13	$	39.99	$	62.66	$	2.07	$	26.68	$	50.10


	Six Months Ended June 30, 2019									Six Months Ended June 30, 2018
(in thousands)	Oil		Natural gas			Natural gas liquids		Total		Oil		Natural gas		Natural gas liquids		Total
Net oil, natural gas and natural gas liquids sales (GAAP)	$	117,850	$	2,765		$	10,255	$	130,870	$	121,448	$	5,091	$	9,866	$	136,405
Plus: Gathering and transportation expenses	599		569			497		1,665		126		137		145		408
Gross oil natural gas and natural gas liquids (non-GAAP)	118,449		3,334			10,752		132,535		121,574		5,228		10,011		136,813
Sales volumes (MBbl/MMcf/MBoe)	2,349		3,512			563		3,497		1,958		2,442		391		2,756
Gross sales price (non-GAAP)	$	50.42	$	0.95		$	19.10	$	37.90	$	62.09	$	2.14	$	25.59	$	49.64