UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

FOR THE QUARTERLY PERIOD ENDED ~~September 30, 2017~~March 31, 2020



o ☐	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)



~~Delaware~~DE		46-5001985
(State or Other Jurisdiction of Incorporation or Organization)		(~~IRS~~I.R.S. Employer Identification Number)

500 West Texas
Suite 1200
Midland, ~~Texas~~	TX	79701
(Address of ~~Principal Executive Offices)~~principal executive offices)		(Zip ~~Code)~~code)

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

(~~Registrant Telephone Number, Including Area Code)~~Registrant's telephone number, including area code)

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



Title of each 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 ~~past~~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. Yesý☒No¨☐

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yesý☒No¨☐

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



Large Accelerated Filer	o☒	Accelerated Filer	ý☐

Non-Accelerated Filer	o☐	Smaller Reporting Company	o☐

		Emerging Growth Company	ý☐

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

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

As of ~~October 20, 2017, 113,882,045~~May 1, 2020, the registrant had outstanding 67,831,342 common units representing limited partner interests and 90,709,946 Class B units ~~of the registrant were outstanding.~~representing limited partner units.

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VIPER ENERGY PARTNERS LP

FORM 10-Q

FOR THE QUARTER ENDED ~~SEPTEMBER 30, 2017~~MARCH 31, 2020

TABLE OF CONTENTS



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

PART I. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited)
~~Consolidated Balance Sheets~~	1
Consolidated Balance Sheets	1
Consolidated Statements of Operations	2
Consolidated Statements of Unitholders’ Equity	3
Consolidated Statements of Cash Flows	4
Condensed Notes to Consolidated Financial Statements	5

Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations	1220

Item 3. Quantitative and Qualitative Disclosures about Market Risk	2130

Item 4. Controls and Procedures	21

~~PART II. OTHER INFORMATION~~

~~Item 1. Legal Proceedings~~	2231

~~Item 1A. Risk Factors~~		22PART II. OTHER INFORMATION

Item ~~6. Exhibits~~1. Legal Proceedings	2233

~~Signatures~~Item 1A. Risk Factors	2333

Item 6. Exhibits	35

Signatures	36

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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	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 of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d	BOE per day.
British Thermal Unit or Btu	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
~~Completion~~Condensate	~~The process of treating a drilled well followed by the installation of permanent equipment for~~Liquid hydrocarbons associated with the production of a primarily natural gas ~~or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.~~reserve.
Crude oil	Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
~~Gross acres or gross wells~~Fracturing	The ~~total acres~~process of creating and preserving a fracture or ~~wells, as~~system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the ~~case may be, in which a working interest is owned.~~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 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 British Thermal Units.
Net royalty acres ~~or net wells~~	~~The sum of~~Gross acreage multiplied by the ~~fractional working interest owned in gross acres.~~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	A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reserves	The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Reserves	The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir	A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or 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.
~~Wellbore~~WTI	~~The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.~~
~~Working interest~~	An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.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.
~~Predecessor~~	~~Viper Energy Partners LLC, a Delaware limited liability company, and a wholly owned subsidiary of the Partnership.~~
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, 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.

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 OPEC members and other oil exporting nations;

the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic, or any government responses to such occurrence or threat;

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

general economic, business or industry conditions;

conditions in the capital, financial and credit markets;

conditions of 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 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;

our ability to replace our oil and natural gas reserves;

our ability to identify, complete and integrate acquisitions of properties or ~~businesses, including our recent and pending acquisitions;~~

~~general economic, business or industry conditions;~~businesses;

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;

future operating results;

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.

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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.

ivv

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PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Viper Energy Partners LP

Consolidated Balance Sheets

(Unaudited)

September 30, December 31,
2017 2016

(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents $ 4,438
$ 9,213
Restricted cash —
500
Royalty income receivable 17,199
10,043
Royalty income receivable—related party 3,646
3,470
Other current assets 147
187
Total current assets 25,430
23,413
Property and equipment:
Oil and natural gas interests, full cost method of accounting ($487,899 and $252,232 excluded from depletion at September 30, 2017 and December 31, 2016, respectively) 1,065,392
760,818
Accumulated depletion and impairment (177,534 ) (148,948 )
Oil and natural gas interests, net 887,858
611,870
Other assets 34,929
35,266
Total assets $ 948,217
$ 670,549
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable $ 110
$ 1,780
Other accrued liabilities 2,747
371
Total current liabilities 2,857
2,151
Long-term debt 35,500
120,500
Total liabilities 38,357
122,651
Commitments and contingencies (Note 10)

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



	March 31,			December 31,
	2020			2019
	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	40,271		$	3,602
Royalty income receivable (net of allowance for doubtful accounts)	37,960			58,089
Royalty income receivable—related party	—			10,576
Derivative instruments	776			—
Other current assets	334			397
Total current assets	79,341			72,664
Property:
Oil and natural gas interests, full cost method of accounting ($1,587,992 and $1,551,767 excluded from depletion at March 31, 2020 and December 31, 2019, respectively)	2,933,085			2,868,459
Land	5,688			5,688
Accumulated depletion and impairment	(351,116		)	(326,474		)
Property, net	2,587,657			2,547,673
Derivative instruments	62			—
Deferred tax asset (net of allowance)	—			142,466
Other assets	12,421			22,823
Total assets	$	2,679,481		$	2,785,626
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	324		$	—
Accounts payable—related party	—			150
Accrued liabilities	16,623			13,282
Derivative instruments	7,362			—
Total current liabilities	24,309			13,432
Long-term debt, net	664,040			586,774
Derivative instruments	965			—
Total liabilities	689,314			600,206
Commitments and contingencies (Note 14)
Unitholders’ equity:
General partner	869			889
Common units (67,831,342 units issued and outstanding as of March 31, 2020 and 67,805,707 units issued and outstanding as of December 31, 2019)	756,408			929,116
Class B units (90,709,946 units issued and outstanding March 31, 2020 and December 31, 2019)	1,105			1,130
Total Viper Energy Partners LP unitholders’ equity	758,382			931,135
Non-controlling interest	1,231,785			1,254,285
Total equity	1,990,167			2,185,420
Total liabilities and unitholders’ equity	$	2,679,481		$	2,785,626

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Operations

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2020			2019
	(In thousands, except per unit amounts)												(In thousands, except per unit amounts)
Operating income:
Royalty income	$	42,211		$	19,992		$	110,194		$	50,914		$	76,829		$	60,428
Lease bonus	322			5			2,613			309
Lease bonus income													1,622			1,160
Other operating income													241			2
Total operating income	42,533			19,997			112,807			51,223			78,692			61,590
Costs and expenses:
Production and ad valorem taxes	2,825			1,429			7,668			4,134			6,147			3,692
Gathering and transportation	205			70			492			247
Depletion	11,068			6,751			28,587			21,485			24,642			16,199
Impairment	—			—			—			47,469
General and administrative expenses	1,368			1,153			5,064			4,109			2,666			1,695
Total costs and expenses	15,466			9,403			41,811			77,444			33,455			21,586
Income (loss) from operations	27,067			10,594			70,996			(26,221		)
Income from operations													45,237			40,004
Other income (expense):
Interest expense	(859		)	(658		)	(2,114		)	(1,544		)
Other income	399			266			526			612
Total other income (expense), net	(460		)	(392		)	(1,588		)	(932		)
Net income (loss)	$	26,607		$	10,202		$	69,408		$	(27,153	)
Interest expense, net													(8,963		)	(4,549		)
Loss on derivative instruments, net													(7,942		)	—
(Loss) gain on revaluation of investment													(10,120		)	3,592
Other income, net													404			656
Total other expense, net													(26,621		)	(301		)
Income before income taxes													18,616			39,703
Provision for (benefit from) income taxes													142,466			(34,608		)
Net (loss) income													(123,850		)	74,311
Net income attributable to non-controlling interest													18,319			40,532
Net (loss) income attributable to Viper Energy Partners LP													$	(142,169	)	$	33,779

Net income attributable to common limited partners per unit:
Basic and Diluted	$	0.24		$	0.12		$	0.69		$	(0.33	)
Weighted average number of limited partner units outstanding:
Net (loss) income attributable to common limited partner units:
Basic	110,377			84,996			101,095			81,496			$	(2.10	)	$	0.61
Diluted	110,424			85,003			101,143			81,496			$	(2.10	)	$	0.61
Weighted average number of common limited partner units outstanding:
Basic													67,822			55,448
Diluted													67,823			55,475

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Unitholders' Equity

(Unaudited)

Limited Partners
Common
Units Amount
(In thousands)
Balance at December 31, 2015 79,726
$ 495,144
Net proceeds from the issuance of common units - public 6,050
93,564
Net proceeds from the issuance of common units - Diamondback 2,000
31,200
Unit-based compensation 24
2,974
Distributions to public
(6,397 )
Distributions to Diamondback
(40,253 )
Net loss
(27,153 )
Balance at September 30, 2016 87,800
$ 549,079

Balance at December 31, 2016 87,800
$ 547,898
Net proceeds from the issuance of common units - public 25,175
369,896
Net proceeds from the issuance of common units - Diamondback 700
10,067
Common units issued for acquisition 175
3,050
Unit-based compensation 32
2,039
Distributions to public
(27,640 )
Distributions to Diamondback
(64,858 )
Net income
69,408
Balance at September 30, 2017 113,882
$ 909,860



	Limited Partners									General Partner			Non-Controlling Interest
	Common					Class B				Amount			Amount
	Units		Amount			Units	Amount			Amount			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



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

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2020			2019
	(In thousands)						(In thousands)
Cash flows from operating activities:
Net income (loss)	$	69,408		$	(27,153	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (loss) income							$	(123,850	)	$	74,311
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes							142,466			(34,655		)
Depletion	28,587			21,485			24,642			16,199
Impairment	—			47,469
Change in fair value of derivative instruments							7,489			—
Loss (gain) on revaluation of investment							10,120			(3,592		)
Amortization of debt issuance costs	434			280			574			216
Non-cash unit-based compensation	2,039			2,974			387			405
Changes in operating assets and liabilities:
Restricted cash	500			—
Royalty income receivable	(7,156		)	(549		)	20,129			740
Royalty income receivable—related party	(176		)	—			10,576			(3,887		)
Accounts payable and accrued liabilities							3,665			(3,289		)
Accounts payable—related party	—			(4		)	(150		)	—
Accounts payable and other accrued liabilities	367			1,707
Income tax payable							—			47
Other current assets	54			345			63			(44		)
Net cash provided by operating activities	94,057			46,554			96,111			46,451
Cash flows from investing activities:
Acquisition of mineral interests	(301,133		)	(137,786		)
Acquisitions of oil and natural gas interests							(64,626		)	(81,923		)
Net cash used in investing activities	(301,133		)	(137,786		)	(64,626		)	(81,923		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	220,500			98,000			92,000			59,500
Repayment on credit facility	(305,500		)	(78,000		)	(15,000		)	(313,500		)
Debt issuance costs	(180		)	(35		)	(26		)	(50		)
Proceeds from public offerings	380,412			125,580			—			340,860
Public offering costs	(433		)	(444		)	—			(212		)
Distributions to partners	(92,498		)	(46,650		)
Units purchased for tax withholding							(383		)	(353		)
Distributions to General Partner							(20		)	(20		)
Distributions to public							(30,214		)	(25,970		)
Distributions to Diamondback							(41,173		)	(37,326		)
Net cash provided by financing activities	202,301			98,451			5,184			22,929
Net increase (decrease) in cash	(4,775		)	7,219			36,669			(12,543		)
Cash and cash equivalents at beginning of period	9,213			539			3,602			22,676
Cash and cash equivalents at end of period	$	4,438		$	7,758		$	40,271		$	10,133

Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	1,781		$	1,251
Interest paid							$	1,617		$	4,908

See accompanying notes to consolidated financial statements.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements

(Unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the ~~NASDAQ~~Nasdaq Global Select Market under the symbol “VNOM”. 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.~~Basin and Eagle Ford Shale. Since May 10, 2018, the Partnership has been treated as a corporation for U.S. federal income tax purposes. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of ~~Viper Energy Partners LP~~the Partnership and its consolidated subsidiary, Viper Energy Partners ~~LLC.~~LLC (the “Operating Company”).

As of ~~September 30, 2017,~~March 31, 2020, Viper Energy Partners GP LLC (the “General Partner”), held a 100% ~~non-economic~~ general partner interest in the Partnership and Diamondback had an approximate ~~64%~~58% limited partner interest in the Partnership. Diamondback owns and controls the General Partner.

Basis of Presentation

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

These 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 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 should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, ~~2016,~~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 are particularly difficult as the oil and gas industry experiences challenges resulting from negative pricing pressure from the effects of a decline in worldwide economic conditions. The decline in worldwide economic conditions is the result of a global COVID-19 pandemic announced in March 2020, which has reduced economic activity and resulted in a significant decline in the short term demand for oil and gas production. Companies in the oil and gas industry are beginning to change near term business plans in response to changing market conditions. The aforementioned circumstances generally increases the estimation uncertainty in our 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, fair value estimates of commodity derivatives, and unit–based compensation.

~~New Accounting Pronouncements~~

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

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

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~~the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only~~

Accounts Receivable

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

The Partnership adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the 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 the Partnership believes collection is doubtful. The Partnership determines its allowance by considering a number of factors, including the Partnership’s previous loss history, the debtor’s current ~~period presented.~~ 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. As the adoption of ASU 2016-13 did not result in a material allowance, no cumulative-effect adjustment was made to beginning unitholders’ equity. At March 31, 2020, the Partnership recorded an allowance for doubtful accounts of $0.2 million related to royalty income receivable. The Partnership did 0t record an allowance for doubtful accounts at December 31, 2019.

Derivative Instruments

The Partnership is ~~currently evaluating the impact of this standard; however, the Partnership has reviewed~~required to recognize its ~~various contracts and has not identified any revenue that would be materially impacted and therefore does not expect the adoption of this standard to have a material impact~~derivative instruments on the ~~Partnership’s financial position, results of operations and liquidity. The Partnership anticipates using the modified retrospective adoption.~~

~~In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial~~consolidated balance sheets as assets or ~~owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured~~liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value recognized in net income. This update will be effective for public entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. Entities should apply the amendments by means of a ~~cumulative-effect adjustment to~~derivative depends on the ~~balance sheet as~~intended use of the ~~beginning of the fiscal year of adoption.~~derivative and resulting designation. The Partnership ~~will be required to mark~~has not designated its ~~cost method investment~~derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value ~~with~~and recognizes the ~~adoption of this update.~~

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognizecash and non-cash change in fair value on derivative instruments for each period in the ~~statement~~consolidated statements of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginningoperations.

Accrued Liabilities

Accrued liabilities consist of the earliest period presented using a modified retrospective approach. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Partnership is still evaluating the impact of this standard.following:



	March 31,		December 31,
	2020		2019
	(In thousands)
Interest payable	$	13,438	$	6,718
Ad valorem taxes payable	2,329		5,632
Other	856		932
Total accrued liabilities	$	16,623	$	13,282

In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-09, "Compensation - Stock Compensation". This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update was effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Partnership prospectively adopted this standard effective January 1, 2017. The Partnership elected to account for forfeitures as they occur as a result of adopting this standard.

In April 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-10, “Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing”. This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity.

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

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

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~~does~~Recent Accounting Pronouncements

The Partnership considers the applicability and impact of all ASUs. ASUs not ~~believe the adoption~~listed below were assessed and determined to be either not applicable or clarifications of ~~this standard will have~~ASUs previously disclosed. The following table provides a ~~material impact on~~brief description of recent accounting pronouncements and the Partnership’s ~~financial statements since the Partnership does not have a history of credit losses.~~

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

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially allanalysis of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This update will be effective foreffects on its financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years. This update should be applied prospectively on or after the effective date. This update is not expected to have a material impact on the Partnership’s financial statements or results of operations. The adoption of this update will change the process that the Partnership uses to evaluate whether the Partnership has acquired a business or an asset. This update will be applied prospectively and will not have an effect on prior acquisitions.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.
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”	This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.	Q1 2020	The Partnership adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 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.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2020-04, “Rate Reform (Topic 848)”	This update provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions that reference LIBOR.	Q1 2020	The Partnership adopted this update upon issuance and elected to use the optional expedient for contracts that reference LIBOR. The amendments in this update expire on December 31, 2022. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
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.

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

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

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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 at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net any deductions for gathering and transportation.

Transaction price allocated to remaining performance obligations

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered 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

The Partnership records revenue in the month production is delivered. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after 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 months ended March 31, 2020, 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

2020 Activity

During the ~~nine~~three months ended ~~September 30, 2017~~,March 31, 2020, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests ~~underlying 2,769~~representing 4,948 gross (410 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $63.4 million, subject to post-closing adjustments and, as of March 31, 2020, had mineral and royalty interests representing 24,714 net royalty acres. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

2019 Activity

During the three months ended March 31, 2019, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests representing 627 net royalty acres for an aggregate purchase price of approximately ~~$304.6~~$82.7 million and, as of ~~September 30, 2017,~~March 31, 2019, had mineral and royalty interests ~~underlying 9,173~~representing 15,469 net royalty acres. The Partnership funded these acquisitions ~~primarily~~ with ~~borrowings under its revolving credit facility, with~~cash on hand, a portion of the net proceeds from its ~~January and July 2017 offerings~~February 2019 offering of common units and ~~with~~borrowings under the ~~issuance of 174,513 common units to a seller in a private placement in May 2017.~~Operating Company’s revolving credit facility.

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5. OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:



	March 31,			December 31,
	2020			2019

	(in thousands)
Oil and natural gas interests:
Subject to depletion	$	1,345,093		$	1,316,692
Not subject to depletion	1,587,992			1,551,767
Gross oil and natural gas interests	2,933,085			2,868,459
Accumulated depletion and impairment	(351,116		)	(326,474		)
Oil and natural gas interests, net	2,581,969			2,541,985
Land	5,688			5,688
Property, net of accumulated depletion and impairment	$	2,587,657		$	2,547,673

Balance of costs not subject to depletion:
Incurred in 2020	$	54,062
Incurred in 2019	827,680
Incurred in 2018	459,094
Incurred in 2017	247,156
Total not subject to depletion	$	1,587,992

September 30, December 31,
2017 2016

(in thousands)
Oil and natural gas interests:
Subject to depletion $ 577,493
$ 508,586
Not subject to depletion 487,899
252,232
Gross oil and natural gas interests 1,065,392
760,818
Accumulated depletion and impairment (177,534 ) (148,948 )
Oil and natural gas interests, net $ 887,858
$ 611,870

Balance of acquisition costs not subject to depletion
Incurred in 2017 $ 250,227

Incurred in 2016 $ 162,984

Incurred in 2015 $ 32,067

Incurred in 2014 $ 42,621

Total not subject to depletion $ 487,899

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

~~Table of Contents~~

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 to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net ~~revenues,~~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 on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Partnership’s oil and natural gas revenue, (b) the cost of interests not being amortized, if any, and (c) the lower of cost or market value of unproved interests included in the cost being amortized. If the net book value exceeds the ceiling, an impairment or non-cash write down is required.

~~As a result of~~After performing the ~~decline in prices,~~ceiling test for the quarter ended March 31, 2020, the Partnership ~~recorded a non-cash impairment for~~was not required to record an impairment. If the nine months ended September 30, 2016 of $47.5 million, which is included in accumulated depletion and impairment. There was no impairment recorded for the nine months ended September 30, 2017. For 2016, the impairment charge affected the Partnership’s reported net loss but did not reduce its cash flow. In addition totrailing 12-month commodity prices continue to fall as compared to the ~~Partnership’s production rates, levels of proved reserves, transfers of unevaluated properties and other factors~~commodity prices used in prior quarters, the Partnership will ~~determine its actual ceiling test limitations and impairment analysis~~have material write downs in ~~future periods.~~subsequent quarters.

5.6. DEBT

~~Credit Agreement-Wells Fargo Bank~~



	March 31,			December 31,
	2020			2019
	(in thousands)
5.375 % Senior Notes due 2027	$	500,000		$	500,000
Revolving credit facility	173,500			96,500
Unamortized debt issuance costs	(2,380		)	(2,458		)
Unamortized discount costs	(7,080		)	(7,268		)
Total long-term debt	$	664,040		$	586,774

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2027 Senior Notes

On October 16, 2019, the Partnership completed an offering (the “Notes Offering”) 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 used the proceeds from the Notes Offering to pay down borrowings under its revolving credit facility.

The Notes are senior unsecured obligations of the Partnership, initially are guaranteed on a senior unsecured basis by the Operating Company and pay interest semi-annually. Neither Diamondback nor the General Partner guarantee the Notes. In the future, each of the Partnership’s restricted subsidiaries that either (1) guarantees any of its or a guarantor’s other indebtedness or (2) is ~~party~~a domestic restricted subsidiary and is an obligor with respect to ~~a secured revolving~~any indebtedness under any credit ~~agreement,~~facility will be required to guarantee the Notes.

Intercompany Promissory Note

In connection with and upon closing of the Notes Offering, the Partnership loaned the gross proceeds from the Notes Offering to the Operating Company under the terms of that certain subordinated promissory note, dated as of October 16, 2019, by the Operating Company in favor of the Partnership (the “Intercompany Promissory Note”). The Intercompany Promissory Note requires the Operating Company to repay the underlying loan to the Partnership on the same terms and in the same amounts as the Notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. The Partnership’s right to receive payment under the Intercompany Promissory Note is contractually subordinated to the Operating Company’s guarantee of the Notes and is structurally subordinated to all of the Operating Company’s secured indebtedness (including all borrowings and other obligations under the Operating Company’s revolving credit facility) to the extent of the value of the collateral securing such indebtedness.

The Operating Company’s Revolving Credit Facility

On July ~~8, 2014,~~20, 2018, the Partnership, as guarantor, entered into an amended and restated credit agreement with the Operating Company, as borrower, Wells Fargo National Bank (“Wells Fargo”), as administrative agent, and the other lenders. The credit agreement, as amended ~~with Wells Fargo, as~~to the ~~administrative agent, sole book runner and lead arranger. The credit agreement~~date hereof, provides for a revolving credit facility in the maximum credit amount of ~~$500.0~~$2.0 billion and a borrowing base based on the Operating Company’s oil and natural gas reserves and other factors (the ‘‘borrowing base’’) of $775.0 million, subject to scheduled semi-annual and other ~~elective collateral~~ borrowing base ~~redeterminations based on the Partnership’s oil and natural gas reserves and other factors.~~redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of ~~April~~May 1st and ~~October~~November 1st. In addition, the ~~Partnership~~Operating Company and Wells Fargo each may request up to ~~three additional~~3 interim redeterminations of the borrowing base during any 12-month period. As of ~~September 30, 2017,~~March 31, 2020, the borrowing base was set at ~~$315.0~~$775.0 million and the ~~Partnership~~Operating Company had ~~$35.5~~$173.5 million inof outstanding borrowings and $601.5 million available for future borrowings under ~~its~~the Operating Company’s revolving credit ~~agreement.~~facility. In connection with the regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent has recommended that the borrowing base be decreased to $580.0 million, which is expected to be effective mid May 2020. The decrease is subject to approval by the requisite lenders under the Operating Company’s revolving credit facility. Under the new expected borrowing base, the Operating Company would have had $406.5 million of availability for future borrowings under the revolving credit facility as of March 31, 2020.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the ~~Partnership~~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 ~~1.00%~~0.75% to ~~2.00%~~1.75% per annum in the case of the alternative base rate and from ~~2.00%~~1.75% to ~~3.00%~~2.75% per annum in the case of LIBOR, in each case depending on the amount of ~~the loan~~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 ~~Partnership~~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 ~~borrowing base,~~commitment, which fee is also dependent on the amount of ~~the loan~~loans and letters of credit outstanding in relation to the ~~borrowing base.~~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 ~~that~~ 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 ~~(b)~~(c) at the maturity date of ~~July 8, 2019.~~November 1, 2022. The loan is secured by substantially all of the assets of the Partnership and ~~its subsidiary.~~the Operating Company.

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, ~~purchases of margin stock,~~ additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of the financial ratios described ~~below.~~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 ~~$250.0 million~~$1.0 billion 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 March 31, 2020, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement. The lenders may accelerate all of the indebtedness under the ~~Partnership’s~~revolving credit ~~agreement~~facility upon the occurrence and during the continuance of any event of default. The ~~Partnership’s~~ credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. ~~There~~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.

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~~Viper Energy Partners LP~~

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

~~(unaudited)~~

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

6.7. RELATED PARTY TRANSACTIONS

Partnership Agreement

~~In connection with the closing of the IPO, the General Partner and Diamondback entered into the first~~The second amended and restated agreement of limited partnership, dated ~~June 23, 2014~~as of May 9, 2018, as amended as of May 10, 2018 (the “Partnership Agreement”)~~. The Partnership Agreement~~, requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on the Partnership’s behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2020 and 2019, the General Partner allocated ~~$0.6~~$0.9 million and ~~$1.8~~$0.6 million, respectively, to the Partnership. ~~During the three and nine months ended September 30, 2016, no expenses were allocated to the Partnership by the General Partner.~~

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

Tax Sharing

In connection with the closing of the IPO, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse 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 March 31, 2020, the Partnership did 0t accrue any state income tax expense. For the three months ended March 31, 2019, the Partnership accrued state income tax expense of $47,364 for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback.

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Lease Bonus

During the three months ended ~~September 30, 2017,~~March 31, 2020, Diamondback, ~~did not pay the Partnership any lease bonus payments. During the nine months ended September 30, 2017, Diamondback~~either directly or through its consolidated subsidiaries, paid the Partnership ~~$0.1~~$0.3 million in lease bonus payments to extend the term of ~~two leases, reflecting an average~~1 lease and $1.3 million in lease bonus ~~of $7,459 per acre.~~payments for 1 new lease. During the three months ended ~~September 30, 2016,~~March 31, 2019, Diamondback paid the Partnership ~~$5,000~~$198 in lease bonus payments to extend the term of ~~two~~1 lease and $3,101 in lease bonus payments for 2 new leases.

Surface Use

Diamondback periodically pays the Partnership for surface use charges and right of way easements related to properties that Diamondback leases ~~reflecting an average bonus of $200 per acre.~~from the Partnership. During the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2020 and 2019, Diamondback paid the Partnership ~~$0.3~~$0.1 million ~~respectively, in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.~~and less than $0.1 million, respectively.

7.8. UNIT-BASED COMPENSATION

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 ~~September 30, 2017,~~March 31, 2020, a total of ~~9,070,356~~8,867,283 common units

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~~(unaudited)~~

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

For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2020, the Partnership incurred ~~$0.5 million and $2.0~~$0.4 million of unit–based compensation.

Phantom Units

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

The following table presents the phantom unit activity under the LTIP for the ~~nine~~three months ended ~~September 30, 2017:~~March 31, 2020:



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	95,248		$	26.87
Vested	(42,814	)	$	23.24
Unvested at March 31, 2020	52,434		$	29.83

Phantom
Units Weighted Average
Grant-Date
Fair Value
Unvested at December 31, 2016 21,048
$ 16.23
Granted 103,190
$ 16.79
Vested (32,176 ) $ 16.49
Unvested at September 30, 2017 92,062
$ 16.77

The aggregate fair value of phantom units that vested during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 was ~~$0.5~~$1.0 million. As of ~~September 30, 2017,~~March 31, 2020, the unrecognized compensation cost related to unvested phantom units was ~~$1.4~~$1.1 million. Such cost is expected to be recognized over a weighted-average period of ~~1.3~~1.41 years.

During the three months ended March 31, 2020, the Partnership modified certain of the phantom units to include distribution equivalent rights during the vesting period. This modification effected 21 awards and resulted in 0 incremental compensation costs to be recognized.

8.9. UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

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

units. At ~~September 30, 2017,~~March 31, 2020, the Partnership had a total of ~~113,882,045~~67,831,342 common units issued and outstanding and 90,709,946 Class B units issued and outstanding, of which ~~73,150,000~~731,500 common units and 90,709,946 Class B units were owned by Diamondback, representing approximately ~~64%~~58% of the 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

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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 ~~units outstanding.~~unit).

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



	Common Units
Balance at December 31, ~~2016~~2019	~~87,800,356~~67,805,707
~~Common units issued in public offerings~~	~~25,875,000~~
Common units vested and issued under the LTIP	~~32,176~~25,635
~~Common units issued for acquisition~~	~~174,513~~
Balance at ~~September 30, 2017~~March 31, 2020	~~113,882,045~~67,831,342

The Partnership had a total of 90,709,946 Class B units outstanding as of March 31, 2020 and December 31, 2019, respectively.

In 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 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 ~~all available cash generated~~ on a quarterly basis ~~beginning with~~all available cash it receives from the ~~quarter ended September 30, 2014.~~Operating Company.

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



	Amount per Common Unit		Declaration Date	Unitholder Record Date	Payment Date
Q4 2019	$	0.45	February 7, 2020	February 21, 2020	February 28, 2020

Amount per Common Unit Declaration Date Unitholder Record Date Payment Date
Q4 2016 $ 0.258
February 3, 2017 February 17, 2017 February 24, 2017
Q1 2017 $ 0.302
April 28, 2017 May 18, 2017 May 25, 2017
Q2 2017 $ 0.332
July 28, 2017 August 17, 2017 August 24, 2017

Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter will be determined by the board of directors of the General Partner following the end of such quarter. Available cash for each quarter will generally equal Adjusted EBITDA reduced for cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors of the General Partner deems necessary or appropriate, if any.

Amendment to LLC Agreement - Tax Allocation Placeholder

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.

9.10. EARNINGS PER UNIT

The net (loss) income per common unit on the consolidated statements of operations is based on the net (loss) income ~~(loss)~~ of the Partnership for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, since this is the amount of net (loss) income ~~(loss)~~ that is attributable to the Partnership’s common units.

The Partnership’s net (loss) income ~~(loss)~~ is allocated wholly to the common ~~units as the General Partner does not have an economic interest.~~units. Payments made to the Partnership’s unitholders are determined in relation to the cash distribution policy described in Note ~~8—Unitholders’~~9—Unitholders' Equity and Partnership Distributions.

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Basic net (loss) income per common unit is calculated by dividing net (loss) income ~~(loss)~~ 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 March 31,
	2020			2019
	(In thousands, except per unit amounts)
Net (loss) income attributable to the period	$	(142,169	)	$	33,779
Less: net income allocated to participating securities⁽¹⁾	(20		)	(42		)
Net (loss) income attributable to common unitholders	$	(142,189	)	$	33,737
Weighted average common units outstanding:
Basic weighted average common units outstanding	67,822			55,448
Effect of dilutive securities:
Potential common units issuable	1			27
Diluted weighted average common units outstanding	67,823			55,475
Net (loss) income per common unit, basic	$	(2.10	)	$	0.61
Net (loss) income per common unit, diluted	$	(2.10	)	$	0.61


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

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
(In thousands, except per unit amounts)
Net income (loss) attributable to the period 26,607
10,202
69,408
(27,153 )
Weighted average common units outstanding
Basic weighted average common units outstanding 110,377
84,996
101,095
81,496
Effect of dilutive securities:
Potential common units issuable 47
7
48
—
Diluted weighted average common units outstanding 110,424
85,003
101,143
81,496
Net income per common unit, basic $0.24 $0.12 $0.69 $(0.33)
Net income per common unit, diluted $0.24 $0.12 $0.69 $(0.33)

For the three months ended ~~September 30, 2017 and 2016,~~March 31, 2020 , there were ~~1,356~~18,169 common units ~~and 1,514,069~~that were not included in the computation of diluted earnings per common ~~units, respectively,~~unit and for the ~~nine~~three months ended ~~September 30, 2017 and 2016,~~March 31, 2019, there were ~~43,414~~0 common units ~~and 1,583,376 common units, respectively,~~ that were not included in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per common unit in future periods.

~~10.~~11. INCOME TAXES

The Partnership’s effective income tax rates were 765.3% and (87.2)% for the three months ended March 31, 2020 and 2019, respectively. Total income tax expense for the three months ended March 31, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of recording a valuation allowance on the Partnership’s deferred tax assets. Total income tax benefit for the three months ended March 31, 2019 differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the revision of estimated deferred taxes recognized as a result of the Partnership’s change in tax status.

For the three months ended March 31, 2020, the Partnership recorded a discrete income tax expense of approximately $142.5 million related to application of a full valuation allowance on the Partnership’s beginning-of-the-year deferred tax assets, which consist primarily of 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 record a valuation allowance was based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets, as required by applicable financial accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the Partnership’s assessment resulted in recording a full valuation allowance against its deferred tax assets as of March 31, 2020.

For the three months ended March 31, 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 consisted primarily of the sum of the Partnership’s unitholders’ tax 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 was not available until unitholders’ tax basis information was fully reported and the Partnership finalized its federal income tax computations for 2018. Based on information available as of March 31, 2019, the Partnership revised its estimate of the difference between its

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tax basis and its basis for financial accounting purposes in the Operating Company on the date of the tax status change, resulting in deferred income tax benefit of $35.2 million included in the Partnership’s income tax provision for the three months ended March 31, 2019.

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 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 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.

12. 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 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 does not require collateral from its counterparties. The Partnership has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.

As of March 31, 2020, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.



	2020
Swaps	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	275,000	$	27.45
Oil Basis Swaps - WTI (Midland-Cushing)	1,100,000	$	(2.60	)
Natural Gas Basis Swaps - Waha Hub	6,875,000	$	(2.07	)

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Collars - WTI (Cushing)	2020		2021
Volume (Bbls)	3,850,000		3,650,000
Floor price (per Bbl)	$	28.86	$	30.00
Ceiling price (per Bbl)	$	32.33	$	43.05

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 that are with the same counterparty and are subject to contractual terms which provide for net settlement.

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 March 31, 2020 and December 31, 2019.



	March 31, 2020			December 31, 2019
	(in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	25,105		$	—
Amounts netted in the Consolidated Balance Sheet	(24,267		)	—
Net amounts of assets presented in the Consolidated Balance Sheet	$	838		$	—

Gross amounts of liabilities presented in the Consolidated Balance Sheet	$	32,594		$	—
Amounts netted in the Consolidated Balance Sheet	(24,267		)	—
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	8,327		$	—

The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Partnership’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:



	March 31, 2020		December 31, 2019
	(in thousands)
Current assets: derivative instruments	$	776	$	—
Noncurrent assets: derivative instruments	62		—
Total assets	$	838	$	—
Current liabilities: derivative instruments	$	7,362	$	—
Noncurrent liabilities: derivative instruments	965		—
Total liabilities	$	8,327	$	—

None of the Partnership’s 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 March 31,
	2020			2019
	(in thousands)

Change in fair value of open non-hedge derivative instruments	$	(7,489	)	$	—
Loss on settlement of non-hedge derivative instruments	(453		)	—
Loss on derivative instruments	$	(7,942	)	$	—

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13. FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Partnership’s derivative instruments and cost method investment. The investment is a Level 1 classification 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 March 31, 2020 and December 31, 2019:



	March 31, 2020						December 31, 2019
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(in thousands)
Assets:
Investment	$	9,237	$	—	$	—	$	19,357	$	—	$	—
Derivative Instruments	—		838		—		—		—		—
Liabilities:
Derivative Instruments	$	—	$	8,327	$	—	$	—	$	—	$	—

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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:



	March 31, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	173,500	$	173,500	$	96,500	$	96,500
5.375% Senior Notes due 2027⁽¹⁾	$	490,540	$	420,150	$	490,274	$	521,100

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

The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the March 31, 2020 quoted market price, a Level 1 classification in the fair value hierarchy.

14. COMMITMENTS AND CONTINGENCIES

The Partnership ~~could be subject~~is a party to various ~~possible loss contingencies which~~legal proceedings, disputes and claims from time to time arising in the 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

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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 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, cash flows or results of operations. 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.

~~11.~~15. SUBSEQUENT EVENTS

Cash Distribution

On ~~October 16, 2017,~~April 30, 2020, the board of directors of the General Partner approved a cash distribution for the ~~third~~first quarter of ~~2017~~2020 of ~~$0.337~~$0.10 per common unit, payable on ~~November 14, 2017,~~May 21, 2020, to eligible unitholders of record at the close of business on ~~November 7, 2017.~~May 14, 2020. This distribution represents 25% of total cash available for distribution with the remaining cash flow expected to be retained to strengthen the Partnership’s balance sheet. The board of directors of the General Partner intends to review this distribution policy quarterly.

The Partnership’s Credit Facility

In connection with the Partnership’s regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent has recommended that the Partnership’s borrowing base be decreased to $580.0 million, which is expected to be effective mid May 2020. The decrease is subject to approval by the requisite lenders under the Operating Company’s revolving credit facility. Under the new expected borrowing base, the Operating Company would have $406.5 million of availability for future borrowings under the revolving credit facility as of March 31, 2020.

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Current Commodity Environment

Oil prices dropped sharply in early March 2020 and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international performance. The Partnership cannot predict when prices will improve and stabilize.

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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, ~~2016.~~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. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking 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. ~~The Partnership is~~We are currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian ~~Basin.~~ 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 ~~September 30, 2017,~~March 31, 2020, our general partner ~~held~~had a 100% ~~non-economic~~ general partner interest in us, and Diamondback ~~had an approximate 64% limited partner interest in us.~~owned 731,500 common units and all of our 90,709,946 outstanding Class B units, representing approximately 58% of our total units outstanding. Diamondback also owns and controls our general partner.

In January 2017, we completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to

Recent Developments

COVID-19 and Recent Collapse in Commodity Prices

On March 11, 2020, the underwriters. We received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which $120.5 million was used to repayWorld Health Organization characterized the ~~outstanding borrowings under our revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.~~

In July 2017, we completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Diamondback purchased 700,000 common units, an affiliate of our general partner purchased 3,000,000 common units and certain officers and directors of Diamondback and our general partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, Diamondback had an approximate 64% limited partner interest in us. We received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which we used $152.8 million to repay allglobal outbreak of the ~~then-outstanding borrowings under our revolving credit facility~~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. Such actions have resulted in a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the ~~balance was used to fund a portion of the purchase price~~demand for ~~acquisitions and for general partnership purposes, which included additional acquisitions.~~

~~We operate in one reportable segment engaged in the acquisition of~~ 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 then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting the supply and demand in global oil and natural gas ~~interests principally located in~~markets, including the ~~Permian Basin~~announcement of ~~West Texas.~~

~~Sources of Our Income~~

~~Our income is derived from royalty payments we receive from our operators based on~~price reductions and production increases by OPEC members and other exporting nations and 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 ofongoing COVID-19 pandemic. The commodity prices ~~production mix and volumes of production sold by our operators.~~

~~Table of Contents~~

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

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Royalty income
Oil sales 85 % 90 % 88 % 91 %
Natural gas sales 7 % 4 % 6 % 4 %
Natural gas liquid sales 8 % 6 % 6 % 5 %
100 % 100 % 100 % 100 %

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

During 2016, West Texas Intermediate posted prices ranged from $26.19 to $54.01 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. During the first nine months of 2017, West Texas Intermediate posted prices ranged from $42.48 to $54.48 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On September 29, 2017, the West Texas Intermediate posted price for crude oil was $51.67 per Bbl and the Henry Hub spot market price of natural gas was $2.94 per MMBtu. Lower prices may not only decrease our income, but also potentially the amount of oil and natural gas ~~that~~production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize.

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. These actions have had and are expected to continue to have an adverse effect on our ~~operators can produce economically. Lower~~business, financial results and cash flows.

Although after performing the ceiling test for the quarter ended March 31, 2020, we were not required to record an impairment on our proved oil and natural gas interests, if the commodity prices continue to fall, we will be required to record impairments in future periods and such impairments may ~~also result in a reduction~~be material. In addition, the administrative agent under the Operating Company’s revolving credit facility has recommended that our borrowing base be decreased to $580.0 million, which is expected to be effective mid May 2020. The decrease is subject to approval by the requisite lenders. Under the new expected borrowing base, the Operating Company would have had $406.5 million of availability for future borrowings under the revolving credit facility as of March 31, 2020. If commodity prices continue at current levels or decrease further, our production, proved reserves and cash flows will be adversely impacted. Our business may be further adversely impacted by any government rule, regulation or order that may impose production limits in the ~~borrowing base under our credit agreement, which may be redetermined at the discretion~~Permian Basin or Eagle Ford Shale, as well as pipeline capacity and storage constraints.

Table of ~~our lenders.~~

Contents

~~Recent Acquisitions~~

Acquisitions Update

During the ~~third~~first quarter of ~~2017,~~2020, we acquired ~~1,677~~mineral and royalty interests, from unrelated third-party sellers’, representing 4,948 gross (410 net ~~royalty~~royalty) acres in the Permian Basin for an aggregate purchase price of ~~$178.9~~approximately $63.4 million, subject to post-closing adjustments ~~bringing our total~~and, as of March 31, 2020, had mineral and royalty interests ~~to 9,173~~representing 24,714 net royalty ~~acres as~~acres. We funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

Cash Distribution Policy Update

On April 30, 2020, the board of ~~September 30, 2017.~~directors of our general partner declared a cash distribution for the three months ended March 31, 2020 of $0.10 per common unit. The distribution is payable on May 21, 2020 to eligible common unitholders of record at the close of business on May 14, 2020. This distribution represents 25% of total cash available for distribution with the remaining cash flow expected to be retained to strengthen our balance sheet. The board of directors of our general partner intends to review this distribution policy quarterly.

Production and Operational Update

Our average daily production during the ~~third~~first quarter of ~~2017~~2020 was ~~12,611~~27,575 BOE/d ~~(68%~~(63% oil), ~~and our~~a 6% increase from the average daily oil production during the first quarter of 2019. Our operators received an average of ~~$45.33~~$45.49 per Bbl of oil, ~~$19.10~~$8.94 per Bbl of natural gas liquids and ~~$2.55~~$0.13 per Mcf of natural gas, for an average realized price of ~~$36.38~~$30.62 per BOE. The average realized price of $0.13 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 first quarter of 2020, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(1.60) 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.

During the ~~third~~first quarter of ~~2017,~~2020, we estimate that 192 gross (4.6 net 100% royalty interest) horizontal wells, in which we have an average royalty interest of 2.4% were turned to production on our existing acreage position with an average lateral length of 9,306 feet. Of these 192 gross wells, Diamondback is the ~~operators~~operator of ~~our Spanish Trail mineral interests brought online nine~~78, in which we have an average royalty interest of 3.8%, and the remaining 114 gross wells, in which have an average royalty interest of 1.4%, are operated by third parties. Additionally, during the first quarter of 2020, we acquired 410 net royalty acres for an aggregate purchase price of approximately $63.4 million, which added a further 92 gross (0.6 net 100% royalty interest) producing horizontal wells with an average royalty interest of ~~12.2%, consisting~~0.6%. In total, as of three Lower Spraberry, four Wolfcamp A, one Wolfcamp B and one Middle Spraberry wells. As of September 30, 2017, there were approximately 24 horizontal wells with an average royalty interest of 21.2% in various stages of drilling or completion on this acreage. Additionally, there is active development activity on our mineral acreage outside of Spanish Trail in Loving, Reeves, Midland, Pecos, Ward, Martin, Howard and Glasscock counties. As of September 30, 2017,March 31, 2020, we had ~~736~~2,454 vertical wells and ~~478~~4,309 horizontal wells producing on our ~~acreage. As~~acreage with a combined average net royalty interest of ~~October 20, 2017,~~3.7%.

Despite the dramatic decline in oil prices, there continues to be active development across our asset base and we currently expect our full year 2020 acreage daily production to be between 22,500 to 27,000 Boe/d. Given the recent extreme weakness in commodity prices and forward pricing uncertainty, our current 2020 production guidance does not account for the potential effect of further production curtailments. Near-term activity is expected to be driven primarily by Diamondback’s operations. To that end, there are 77 gross horizontal wells operated by Diamondback currently in the process of development on our royalty acreage, in which we expect to own an average 6.6% net royalty interest (5.1 net 100% royalty interest wells). These wells currently in the process of active development include various wells being drilled by the 12 active Diamondback rigs which were on our acreage as of April 22, 2020, 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, based on Diamondback’s current completion schedule, we have line-of-sight to a further 50 gross (4.1 net 100% royalty interest) wells for which the process of active development has not yet begun, but for which we have visibility to the potential of future development in coming quarters. There is currently less visibility into third party operators’ anticipated activity levels and well completion cadence given the current commodity price environment. 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 and tight physical markets. Notwithstanding the foregoing, third parties continue to operate on our asset base. There are 492 gross horizontal wells operated by third parties in the process of active development, in which we expect to own an average 0.9% net royalty interest (4.4 net 100% royalty interest wells). Additionally, there are 379 gross (4.2 net 100% royalty interest) wells operated by third parties that have been permitted but not yet begun the process of active development. In total, as of April 22, 2020, between Diamondback and third party operators, there were 22569 (9.5 net 100% royalty interest) wells currently in the process of active development, including 37 active rigs, and ~~319~~a further 429 gross (8.2 net 100% royalty interest) line-of-sight wells which have not yet begun the process of active ~~horizontal drilling permits on our acreage. We intend to continue to be active in acquiring mineral interests with near term visibility and accretive cash flow growth.~~

~~We declared a cash dividend for~~development. The acquisitions that we closed during the ~~third~~first quarter of ~~2017 of $0.337 per common unit, payable on November 14, 2017, to unitholders of record at the close of business on November 7, 2017.~~

~~Principal Components of Our Cost Structure~~

~~Production and Ad Valorem Taxes~~

Production 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 taxes2020 contributed 39 gross (0.2 net 100% royalty interest) horizontal wells in the ~~counties where our production is located. Ad valorem taxes are generally based on~~process of active development out of the ~~valuation of our oil and gas interests.~~total 569

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~~General and Administrative~~

~~In connection with the closing~~currently in our portfolio. Further, these recent acquisitions also contributed 18 gross (0.1 net 100% royalty interest) permits out 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 expensestotal 429 total gross line-of-sight wells 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.~~process of active development has not yet begun.

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

~~Depreciation, Depletion and Amortization~~

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

~~Income Tax Expense~~

~~We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income.~~

~~We are subject to the Texas margin tax. Diamondback does not expect any Texas margin tax to be due for the nine months ended September 30, 2017 or 2016.~~

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Results of Operations

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

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
(unaudited, in thousands, except production data)
Operating Results:
Operating income:
Royalty income $ 42,211
$ 19,992
$ 110,194
$ 50,914
Lease bonus 322
5
2,613
309
Total operating income 42,533
19,997
112,807
51,223
Costs and expenses:
Production and ad valorem taxes 2,825
1,429
7,668
4,134
Gathering and transportation 205
70
492
247
Depletion 11,068
6,751
28,587
21,485
Impairment —
—
—
47,469
General and administrative expenses 1,368
1,153
5,064
4,109
Total costs and expenses 15,466
9,403
41,811
77,444
Income (loss) from operations 27,067
10,594
70,996
(26,221 )
Other income (expense):
Interest expense (859 ) (658 ) (2,114 ) (1,544 )
Other income 399
266
526
612
Total other income (expense), net (460 ) (392 ) (1,588 ) (932 )
Net income (loss) $ 26,607
$ 10,202
$ 69,408
$ (27,153 )

Production Data:
Oil (Bbls) 794,375
430,732
2,077,570
1,236,003
Natural gas (Mcf) 1,236,349
315,030
2,460,535
1,008,745
Natural gas liquids (Bbls) 159,806
92,221
393,913
221,582
Combined volumes (BOE) 1,160,239
575,458
2,881,572
1,625,709
Daily combined volumes (BOE/d) 12,611
6,255
10,555
5,933
% Oil 68 % 75 % 72 % 76 %

Average sales prices:
Oil, realized ($/Bbl) $ 45.33
$ 41.97
$ 46.51
$ 37.64
Natural gas realized ($/Mcf) 2.55
2.39
2.62
1.89
Natural gas liquids ($/Bbl) 19.10
12.56
18.07
11.25
Average price realized ($/BOE) 36.38
34.74
38.24
31.32

Average Costs ($/BOE)
Production and ad valorem taxes $ 2.43
$ 2.48
$ 2.66
$ 2.54
Gathering and transportation expense 0.18
0.12
0.17
0.15
General and administrative - cash component 0.75
0.19
1.05
0.70
Total operating expense - cash $ 3.36
$ 2.79
$ 3.88
$ 3.39

General and administrative - non-cash component $ 0.43
$ 1.81
$ 0.71
$ 1.83
Interest expense 0.74
1.14
0.73
0.95
Depletion 9.54
11.73
9.92
13.22



	Three Months Ended March 31,
	2020			2019
	(in thousands)
Operating Results:
Operating income:
Royalty income	$	76,829		$	60,428
Lease bonus income	1,622			1,160
Other operating income	241			2
Total operating income	78,692			61,590
Costs and expenses:
Production and ad valorem taxes	6,147			3,692
Depletion	24,642			16,199
General and administrative expenses	2,666			1,695
Total costs and expenses	33,455			21,586
Income from operations	45,237			40,004
Other income (expense):
Interest expense, net	(8,963		)	(4,549		)
Loss on derivative instruments, net	(7,942		)	—
(Loss) gain on revaluation of investment	(10,120		)	3,592
Other income, net	404			656
Total other expense, net	(26,621		)	(301		)
Income before income taxes	18,616			39,703
Provision for (benefit from) income taxes	142,466			(34,608		)
Net (loss) income	(123,850		)	74,311
Net income attributable to non-controlling interest	18,319			40,532
Net (loss) income attributable to Viper Energy Partners LP	$	(142,169	)	$	33,779

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	Three Months Ended March 31,
	2020			2019

Production Data:
Oil (MBbls)	1,587			1,147
Natural gas (MMcf)	2,658			1,872
Natural gas liquids (MBbls)	479			254
Combined volumes (MBOE)	2,509			1,714

Average daily oil volumes (BO/d)	17,441			12,750
Average daily combined volumes (BOE/d)	27,575			19,042

Average sales prices:
Oil ($/Bbl)	$	45.49		$	45.31
Natural gas ($/Mcf)⁽¹⁾	$	0.13		$	2.05
Natural gas liquids ($/Bbl)	$	8.94		$	18.09
Combined ($/BOE)	$	30.62		$	35.26

Oil, hedged ($/Bbl)⁽²⁾	$	45.49		$	45.31
Natural gas, hedged ($/MMbtu)⁽²⁾	$	(0.04	)	$	2.05
Natural gas liquids ($/Bbl)⁽²⁾	$	8.94		$	18.09
Combined price, hedged ($/BOE)⁽²⁾	$	30.44		$	35.26

Average Costs ($/BOE):
Production and ad valorem taxes	$	2.45		$	2.15
General and administrative - cash component	0.91			0.75
Total operating expense - cash	$	3.36		$	2.90

General and administrative - non-cash component	$	0.15		$	0.24
Interest expense, net	$	3.57		$	2.65
Depletion	$	9.82		$	9.45

(1)

The average realized price of $0.13 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 first quarter of 2020, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(1.60) 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.


(2)	Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. We did not have any derivative contracts prior to February of 2020.

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Comparison of the Three Months Ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019

Royalty Income

Our royalty income for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019 was ~~$42.2~~$76.8 million and ~~$20.0~~$60.4 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.

~~In addition to the increase~~The decrease in average prices received during the three months ended ~~September 30, 2017, we also benefited from~~March 31, 2020 as compared to the three months ended March 31, 2019 was partially offset by a ~~101.6%~~46% increase in combined volumes sold by our operators as compared to the three months ended ~~September 30, 2016.~~March 31, 2019.


	Change in prices		Production volumes⁽¹⁾		Total net dollar effect of change		Change in prices			Production volumes⁽¹⁾		Total net dollar effect of change
					(in thousands)							(in thousands)
Effect of changes in price:
Oil	$	3.36	794,375		$	2,669	$	0.19		1,587		$	294
Natural gas							$	(1.92	)	2,658		(5,109		)
Natural gas liquids	6.54		159,806		1,045		$	(9.15	)	479		(4,383		)
Natural gas	0.16		1,236,349		198
Total income due to change in price					$	3,912						$	(9,198	)

	Change in production volumes⁽¹⁾		Prior period average prices		Total net dollar effect of change		Change in production volumes⁽¹⁾			Prior period average prices		Total net dollar effect of change
					(in thousands)							(in thousands)
Effect of changes in production volumes:
Oil	363,643		$	41.97	$	15,256	440			$	45.31	$	19,919
Natural gas							787			$	2.05	1,614
Natural gas liquids	67,585		12.56		849		225			$	18.09	4,066
Natural gas	921,319		2.39		2,202
Total income due to change in production volumes					18,307							25,599
Total change in income					$	22,219						$	16,401


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

Lease Bonus Income

Lease bonus income increased by ~~$0.3~~$0.5 million for the three months ended ~~September 30, 2017~~March 31, 2020 as compared to the three months ended ~~September 30, 2016.~~March 31, 2019. During the three months ended ~~September 30, 2017,~~March 31, 2020, we received $0.3 million in lease bonus payments to extend the term of one lease ~~reflecting~~and $1.3 million for two new leases. During the three months ended March 31, 2019, we received $44,688 in lease bonus payments to extend the term of five leases and $1.1 million for six new leases.

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Production and Ad Valorem Taxes

Production taxes per unit of production for the three months ended March 31, 2020 and 2019 were $1.43 and $1.75, respectively. The decrease in production taxes per unit of production during the three months ended March 31, 2020 was primarily due to a higher percentage increase in production volumes as compared to production taxes. Ad valorem taxes per unit of production for the three months ended March 31, 2020 and 2019 were $1.02 and $0.40, respectively. The increase in ad valorem taxes per unit of production during the three months ended March 31, 2020 was primarily due to an ~~average bonus~~increase in production volumes from wells drilled and acquired in 2019, along with an increase in the valuation of ~~$10,000 per acre.~~oil and natural gas interests year over year.



	Three Months Ended March 31,
	2020				2019
	Amount (in thousands)		Per BOE		Amount (in thousands)		Per BOE
Production taxes	$	3,575	$	1.43	$	3,008	$	1.75
Ad valorem taxes	2,572		1.02		684		0.40
Total production and ad valorem taxes	$	6,147	$	2.45	$	3,692	$	2.15

Depletion

Depletion expense increased by $8.4 million to $24.6 million for the three months ended March 31, 2020 from $16.2 million for the three months ended March 31, 2019. The increase 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 ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, we incurred general and administrative expenses of ~~$1.4~~$2.7 million and $1.2 million, respectively. The increase of $0.2 million during the three months ended September 30, 2017 was primarily due to the reimbursement of expenses to the General Partner under the Partnership Agreement, partially offset by a decrease in unit-based compensation expense.

~~Net Interest Expense~~

The net interest expense for the three months ended September 30, 2017 and 2016 reflects the interest incurred under our credit agreement. Net interest expense for the three months ended September 30, 2017 and 2016 was $0.9 million and $0.7 million, respectively. The increase of $0.2 million was due to a higher interest rate and increased borrowings during the three months ended September 30, 2017 as compared to the three months ended September 30, 2016.

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

~~Royalty Income~~

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

In addition to the increase in average prices received during the nine months ended September 30, 2017, we also benefited from a 77.3% increase in combined volumes sold by our operators as compared to the nine months ended September 30, 2016.

Change in prices
Production volumes⁽¹⁾
Total net dollar effect of change
(in thousands)
Effect of changes in price:
Oil $ 8.87
2,077,570
$ 18,433
Natural gas liquids 6.82
393,913
2,686
Natural gas 0.73
2,460,535
1,796
Total income due to change in price $ 22,915

Change in production volumes⁽¹⁾
Prior period average prices Total net dollar effect of change
(in thousands)
Effect of changes in production volumes:
Oil 841,567
$ 37.64
$ 31,682
Natural gas liquids 172,331
11.25
1,939
Natural gas 1,451,790
1.89
2,744
Total income due to change in production volumes 36,365
Total change in income $ 59,280


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

~~Lease Bonus Income~~

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

~~Impairment of Oil and Gas Properties~~

During the nine months ended September 30, 2016, we recorded an impairment of oil and gas properties of $47.5 million as a result of the significant decline in commodity prices. No impairment was recorded for the nine months ended September 30, 2017.

~~General and Administrative Expenses~~

~~For the nine months ended September 30, 2017 and 2016, we incurred general and administrative expenses of $5.1 million and $4.1~~$1.7 million, respectively. The increase of $1.0 million during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 was ~~primarily~~ due to ~~the reimbursement of~~an increase in expenses toallocated from the General Partner under the Partnership Agreement, ~~partially offset by a decrease~~an increase in ~~unit-based compensation expense.~~software expenses, bad debt expense and additional professional service fees attributable to acquisitions.

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Net Interest Expense

~~The net interest expense for the nine months ended September 30, 2017 and 2016 reflects the interest incurred under our credit agreement.~~ Net interest expense for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019 was ~~$2.1~~$9.0 million and ~~$1.5~~$4.5 million, respectively. The increase of ~~$0.6~~$4.4 million in net interest expense for three months ended March 31, 2020 as compared to 2019 was due to ~~a higher interest rate and~~ increased borrowings and our senior notes issued in October 2019.

Derivatives

We recorded a loss on derivatives for the three months ended March 31, 2020 of $7.9 million. We had no derivatives during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 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 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.”

Provision for (Benefit from) Income Taxes

We recorded income tax expense of $142.5 million and income tax benefit of $34.6 million for the three months ended March 31, 2020 and 2019, respectively. The change in our income tax provision was primarily due to the ~~nine~~application of a valuation allowance on the our deferred tax assets during the three months ended ~~September 30, 2016.~~March 31, 2020, and the revision during the three months ended March 31, 2019 of estimated deferred taxes recognized as a result of our change in federal income tax status. Total income tax provision for the three months ended March 31, 2020 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to impact of recording a valuation allowance on our deferred tax assets and net income attributable to the non-controlling interest.

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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.

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

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

The following table presents a reconciliation of Adjusted EBITDA to net income (loss), our most directly comparable GAAP financial measure for the periods ~~indicated.~~indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
(In thousands)
Net income (loss) $ 26,607
$ 10,202
$ 69,408
$ (27,153 )
Interest expense 859
658
2,114
1,544
Non-cash unit-based compensation expense 503
1,044
2,039
2,974
Depletion 11,068
6,751
28,587
21,485
Impairment —
—
—
47,469
Adjusted EBITDA $ 39,037
$ 18,655
$ 102,148
$ 46,319



	Three Months Ended March 31,
	2020			2019
	(In thousands)
Net (loss) income	$	(123,850	)	$	74,311
Interest expense, net	8,963			4,549
Non-cash unit-based compensation expense	387			405
Depletion	24,642			16,199
(Loss) gain on revaluation of investment	10,120			(3,592		)
Non-cash loss on derivative instruments, net	7,489			—
Provision for (benefit from) income taxes	142,466			(34,608		)
Consolidated Adjusted EBITDA	70,217			57,264
EBITDA attributable to non-controlling interest	(40,175		)	(30,708		)
Adjusted EBITDA attributable to Viper Energy Partners LP	$	30,042		$	26,556

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 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. 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 March 31, 2020								Three Months Ended March 31, 2019
(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)	$	72,200	$	344	$	4,285	$	76,829	$	51,987	$	3,839	$	4,602	$	60,428
Plus: Gathering and transportation expenses	287		414		380		1,081		234		305		249		788
Gross oil, natural gas and natural gas liquids sales (non-GAAP)	$	72,487	$	758	$	4,665	$	77,910	$	52,221	$	4,144	$	4,851	$	61,216
Sales volumes (MBbl/MMcf/MBbl/MBOE)	1,587		2,658		479		2,509		1,147		1,872		254		1,714
Gross sales price (non-GAAP)	$	45.67	$	0.29	$	9.74	$	31.05	$	45.51	$	2.21	$	19.07	$	35.72

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 primary uses of cash have been, and are expected to continue to be, distributions to our unitholders and replacement and growth capital expenditures, including the acquisition of 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 of the cash we generate from operations. ~~We believe, however, that it is in~~However, the ~~best interests of our unitholders if we distribute a substantial portion of the cash we generate from operations. The~~ board of directors of our general partner has adopted a policy pursuant to which the Operating Company will distribute ~~an amount equal~~all of the available cash it generates each quarter to its unitholders (including us), and we, in turn, will distribute all of the available cash we ~~generate each quarter~~receive from the Operating Company to our common unitholders.

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

Cash distributions are made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for 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 cash for the Operating Company for each quarter will generally ~~equals~~equal its Adjusted EBITDA reduced for 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 available cash will generally equal our Adjusted EBITDA (which will be our proportionate share of the available cash distributed to us by the Operating Company), less, as a result of the our election to be treated as a corporation for U.S. federal income tax purposes effective, May 10, 2018, cash needed for the payment of income taxes payable by us, if any.

~~January 2017 Public~~On April 30, 2020, the board of directors of our general partner approved a cash distribution for the first quarter of 2020 of $0.10 per common unit, payable on May 21, 2020, to eligible unitholders of record at the close of business on May 14, 2020.

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2019 Equity Offering

In ~~January 2017,~~March 2019, we completed an underwritten public offering of ~~9,775,000~~10,925,000 common units, which included ~~1,275,000~~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 ~~$147.5~~$340.6 million, after deducting underwriting discounts and commissions and estimated offering ~~expenses, of which $120.5 million was~~expenses. We used ~~to repay~~ the ~~outstanding borrowings under our revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.~~

~~July 2017 Public Offering~~

~~In July 2017, we completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option~~net proceeds to purchase ~~additional common~~ units ~~granted to~~of the ~~underwriters. We received~~Operating Company. The Operating Company in turn used the net proceeds ~~from this offering of approximately $232.5 million, after deducting underwriting discounts and commission and estimated offering expenses, of which $152.8 million was used~~ to repay all of the then-outstanding borrowings under our revolving credit facility, and the balance was used to fund a portion of the purchase price for acquisitions and for general corporate purposes, which included additional acquisitions.

~~Our Credit Agreement~~

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

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

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



~~Financial Covenant~~		~~Required Ratio~~
~~Ratio of total debt to EBITDAX~~		~~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 $250.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the

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

~~The lenders may accelerate all of the indebtedness~~borrowings under the Operating Company’s revolving credit ~~agreement upon the occurrence~~facility and finance acquisitions during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.period.

Cash Flows

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

Nine Months Ended September 30,
2017 2016

(in thousands)
Cash Flow Data:
Net cash flows provided by operating activities $ 94,057
$ 46,554
Net cash flows used in investing activities (301,133 ) (137,786 )
Net cash flows provided by financing activities 202,301
98,451
Net increase (decrease) in cash $ (4,775 ) $ 7,219



	Three Months Ended March 31,
	2020			2019

	(in thousands)
Cash Flow Data:
Net cash provided by operating activities	$	96,111		$	46,451
Net cash used in investing activities	(64,626		)	(81,923		)
Net cash provided by financing activities	5,184			22,929
Net increase (decrease) in cash	$	36,669		$	(12,543	)

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.

Investing Activities

Net cash used in investing activities was ~~$301.1~~$64.6 million and ~~$137.8~~$81.9 million during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, respectively, and related to acquisitions of ~~mineral interests.~~oil and natural gas interests and land.

Financing Activities

Net cash provided by financing activities was ~~$202.3~~$5.2 million during the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2020, primarily related to net ~~proceeds~~borrowing activity under the Operating Company’s revolving credit facility of ~~$380.0~~$77.0 million ~~from our public offerings of common units,~~and partially offset by ~~the repayment of $85.0 million net of borrowings under our revolving credit agreement and~~ distributions of ~~$92.5~~$71.4 million to our unitholders during the period. Net cash provided by financing activities was ~~$98.5~~$22.9 million during the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2019, primarily related to ~~$20.0 million of net borrowings under our revolving credit agreement and~~ net proceeds ~~of $125.1 million~~ from our public offering of common units of $340.6 million, partially offset by ~~$46.7~~net repayments on borrowings of $254.0 million under the revolving credit facility and distributions of ~~distributions~~$63.3 million to our unitholders during that period.

The Operating Company’s Revolving Credit Facility

On July 20, 2018, we, as guarantor, entered into an amended and restated credit agreement with the Operating Company, as borrower, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended to the date hereof, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on our oil and natural gas reserves and other factors of $725.0 million, subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing 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. As of March 31, 2020, the borrowing base was set at $775.0 million and the Operating Company had $173.5 million of outstanding borrowings and $601.5 million available for future borrowings under the Operating Company’s revolving credit facility. In connection with our regularly scheduled (semi-annual) spring 2020 redetermination, our administrative agent has recommended that our borrowing base be decreased to $580.0 million, which is expected to be effective

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mid May 2020. The decrease is subject to approval by the requisite lenders under the Operating Company’s revolving credit facility. Under the new expected borrowing base, the Operating Company would have had $406.5 million of availability for future borrowings under the revolving credit facility as of March 31, 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.

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 $1.0 billion 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 March 31, 2020, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement. The lenders may accelerate all of the indebtedness under the Operating 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 our credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Notes Offering

On October 16, 2019, we issued our 5.375% Senior Notes due 2027 in the aggregate principal amount of $500.0 million (which we refer to as the Notes) 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 Notes Offering to the Operating Company. The Operating Company used the proceeds from the Notes Offering to repay then outstanding borrowings under its revolving credit facility. Interest on the 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 November 1 of each year, commencing on May 1, 2020. The Notes will mature on November 1, 2027.

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The Operating Company guaranteed the Notes pursuant to the Indenture. Neither Diamondback nor the General Partner guarantees the Notes. The Indenture contains restrictive certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets including equity of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens and designate certain of our subsidiaries as unrestricted subsidiaries. Certain of these covenants are subject to termination upon the occurrence of certain events. We may use cash on hand to repurchase a portion of the Notes in privately negotiated transactions, open market purchases or otherwise, but we are under no obligation to do so.

Intercompany Promissory Note

In connection with and upon closing of the Notes Offering, we loaned the gross proceeds from the Notes Offering to the Operating Company under the terms of that certain subordinated promissory note, dated as of October 16, 2019, by the Operating Company in favor of us, which we refer to as the Intercompany Promissory Note. The Intercompany Promissory Note requires the Operating Company to repay the underlying loan to us on the same terms and in the same amounts as the Notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. Our right to receive payment under the Intercompany Promissory Note is contractually subordinated to the Operating Company’s guarantee of the notes and is structurally subordinated to all of the Operating Company’s secured indebtedness (including all borrowings and other obligations under the Operating Company’s revolving credit facility) to the extent of the value of the collateral securing such indebtedness.

Contractual Obligations

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, ~~2016.~~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, ~~2016.~~2019.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

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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 ~~driven~~ by the prevailing worldwide price for crude oil and ~~spot market~~ prices ~~applicable to our~~for natural gas ~~production.~~in the United States. Both crude oil and natural gas realized prices are also impacted by the quality of the product, supply and demand balances in local physical markets and the availability of transportation to demand centers. Pricing for oil and natural gas production has been historically volatile and unpredictable ~~particularly 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 levels below zero dollars per barrel. This was as a result of multiple factors affecting supply and demand in the global oil and gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international performance. We cannot predict when prices will improve and stabilize.

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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 March 31, 2020, we had a net liability derivative position related to our commodity price derivatives of $7.5 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 March 31, 2020, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $13.3 million, an increase of $5.8 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position to $1.7 million, an decrease of $5.8 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 significant ~~purchasers.~~purchasers and producers. For the ~~nine~~three months ended ~~September 30, 2017, two~~March 31, 2020, three purchasers each accounted for more than 10% of our royalty income: Trafigura Trading LLC (28%), Vitol Midstream Pipeline LLC (16%) and Shell Trading (US) Company ~~(48%) and RSP Permian LLC (23%~~(16%). For the ~~nine~~three months ended ~~September 30, 2016, two~~March 31, 2019, three purchasers each accounted for more than 10% of our royalty income: Trafigura Trading LLC (38%), Concho Resources, Inc. (13%) and Shell Trading (US) Company ~~(63%) and RSP Permian LLC (28%~~(11%). We do not require collateral and ~~do not believe~~ the ~~loss~~inability of ~~any single~~our significant purchasers to meet their obligations to us or their 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 credit agreement. The terms of our credit agreement provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from ~~1.00%~~0.75% to ~~2.00%~~1.75% in the case of the alternative base rate and from ~~2.00%~~1.75% to ~~3.00%~~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 ~~September 30, 2017,~~March 31, 2020, we had ~~$35.5~~$173.5 million in outstanding borrowings. Our weighted average interest rate on borrowings under our revolving credit facility was ~~3.24%~~2.78%. An increase or decrease of 1% in the interest rate would have a corresponding ~~decrease~~increase or ~~increase~~decrease in our interest expense of approximately ~~$0.4~~$1.7 million based on the ~~$35.5~~$173.5 million outstanding in the aggregate under our credit agreement.

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 ~~September 30, 2017,~~March 31, 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 operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner have concluded that as of ~~September 30, 2017,~~March 31, 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 ~~September 30, 2017~~March 31, 2020 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Note 14—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 to the information set forth in this report, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10–K for the year ended December 31, ~~2016~~2019 and in subsequent filings we make with the ~~SEC. There~~SEC, as well as risk factors set forth below.

Our business has been and will likely continue to be adversely affected by the recent COVID-19 coronavirus outbreak

The spread of COVID-19 caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economy, including the global and domestic demand for oil and natural gas, which could have ~~been no~~an adverse effect on our operators and, in turn, on our business, financial condition and cash flows. Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 could also negatively impact the availability of key personnel necessary to conduct our business. If COVID-19 continues to spread or the response to contain the COVID-19 pandemic is unsuccessful, we could continue to experience material adverse effects on our business, financial condition and cash available for distribution to our unitholders. Due to the rapid development and fluidity of this situation, we cannot make any prediction as to the ultimate material adverse impact of the COVID -19 pandemic on our business, financial condition and cash available for distribution to our unitholders.

The sharp decline in oil and natural gas prices and continued volatility in the oil and natural gas markets have negatively impacted, and are likely to continue to negatively impact, exploration and production activities of our operators and, as a result, our revenue and cash available for distribution to our unitholders.

Oil prices dropped sharply in early March 2020 and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting the supply and demand in global oil and gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize.

Other significant factors that are likely to continue to affect commodity prices in current and future periods include, but are not limited to, actions by OPEC members and other oil exporting nations, the effect of U.S. energy, monetary and trade policies, U.S. and global economic conditions, U.S. and global political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental policies, the impact of the ongoing COVID-19 pandemic and conditions in the U.S. oil and gas industry, all of which are beyond our ~~risk~~control.

The current prices of oil, natural gas and natural gas liquids, as well as ongoing volatility, have had an adverse impact on the level of drilling and exploration and production activity of our operators, which could continue to materially and adversely affect. As a result of the reduction in crude oil demand caused by factors ~~from those described~~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. These actions have had and are expected to continue to have an adverse effect on our ~~Annual Report on Form 10–K~~business, financial results and cash flows and, given the recent extreme weakness in commodity prices and forward pricing uncertainty, our current production guidance does not account for the ~~year~~potential effect of further production curtailments. Lower commodity prices may also adversely impact estimates of our proved reserves.

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Although after performing the ceiling test for the quarter ended ~~December~~March 31, ~~2016.~~2020, we were not required to record an impairment on our proved oil and natural gas interests, if the commodity prices continue to fall, we will be required to record impairments in future periods and such impairments may be material. In addition, the administrative agent under the Operating Company’s revolving credit facility has recommended that our borrowing base be decreased to $580.0 million and is expected to be effective mid May 2020, subject to approval by the requisite lenders under the Operating Company’s revolving credit facility. Under the new expected borrowing base, the Operating Company would have had $406.5 million of availability for future borrowings under the revolving credit facility as of March 31, 2020.

Our business may be also adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin or Eagle Ford Shale where we have mineral and royalty interests.

We cannot predict the ultimate impact of these factors on our business, financial condition and cash available for distribution to our unitholders.

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ITEM 6. EXHIBITS



Exhibit Number	Description
3.1	Certificate of Limited Partnership of Viper Energy Partners LP ~~(Incorporated~~(incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File ~~No.~~ 333-195769) filed on May 7, 2014).
3.2	~~First~~Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, ~~(Incorporated~~dated as of May 9, 2018 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File ~~No.~~ 001-36505) filed on ~~June 23, 2014)~~May 15, 2018).
3.3	First Amendment to Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 10, 2018. (incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.4	Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of May 9, 2018. (incorporated by reference to Exhibit 3.3 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.5	First Amendment to Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of March 30, 2020 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on March 31, 2020).
4.1	Description of Securities of the Partnership (incorporated by reference to Exhibit 4.1 of the Partnership’s Annual Report on Form 10-K (File 001-36505) filed on February 18, 2020).
4.2	Amended and Restated Registration Rights Agreement, dated ~~June 23, 2014,~~as of May 9, 2018, by and between Viper Energy Partners LP and Diamondback Energy, Inc. ~~(Incorporated~~(incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File ~~No.~~ 001-36505) filed on ~~June 23, 2014)~~May 15, 2018).
10.1+	Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.8 of the Partnership’s Annual Report on Form 10-K (File 001-36505) filed on February 18, 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 following financial information from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, formatted in 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*104.0	Cover Page Interactive Data File (formatted as Inline 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.~~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.
+	Management contract, compensatory plan or arrangement.

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SIGNATURES

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



		VIPER ENERGY PARTNERS LP

		By:	VIPER ENERGY PARTNERS GP LLC
			its General Partner

Date:	~~October 25, 2017~~May 7, 2020	By:	/s/ Travis D. Stice
			Travis D. Stice
			Chief Executive Officer

Date:	~~October 25, 2017~~May 7, 2020	By:	/s/ Teresa L. Dick
			Teresa L. Dick
			Chief Financial Officer

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	September 30,			December 31,
	2017			2016

	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	4,438		$	9,213
Restricted cash	—			500
Royalty income receivable	17,199			10,043
Royalty income receivable—related party	3,646			3,470
Other current assets	147			187
Total current assets	25,430			23,413
Property and equipment:
Oil and natural gas interests, full cost method of accounting ($487,899 and $252,232 excluded from depletion at September 30, 2017 and December 31, 2016, respectively)	1,065,392			760,818
Accumulated depletion and impairment	(177,534		)	(148,948		)
Oil and natural gas interests, net	887,858			611,870
Other assets	34,929			35,266
Total assets	$	948,217		$	670,549
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	110		$	1,780
Other accrued liabilities	2,747			371
Total current liabilities	2,857			2,151
Long-term debt	35,500			120,500
Total liabilities	38,357			122,651
Commitments and contingencies (Note 10)
Unitholders’ equity:
Common units (113,882,045 units issued and outstanding as of September 30, 2017 and 87,800,356 units issued and outstanding as of December 31, 2016 )	909,860			547,898
Total unitholders’ equity	909,860			547,898
Total liabilities and unitholders’ equity	$	948,217		$	670,549



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2016	21,048		$	16.23
Granted	103,190		$	16.79
Vested	(32,176	)	$	16.49
Unvested at September 30, 2017	92,062		$	16.77