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Viper Energy Partners Lp (VNOM) SEC Filing 10-Q Quarterly report for the period ending Wednesday, September 30, 2020

Viper Energy Partners Lp

CIK: 1602065 Ticker: VNOM


Exhibit 99.1
viperlogoa301.gif

VIPER ENERGY PARTNERS LP, A SUBSIDIARY OF DIAMONDBACK ENERGY, INC., REPORTS THIRD QUARTER 2020 FINANCIAL AND OPERATING RESULTS

MIDLAND, Texas, November 2, 2020
(GLOBE NEWSWIRE) -- Viper Energy Partners LP (NASDAQ:VNOM) (“Viper” or the “Company”), a subsidiary of Diamondback Energy, Inc. (NASDAQ:FANG) (“Diamondback”), today announced financial and operating results for the third quarter ended September 30, 2020.
THIRD QUARTER HIGHLIGHTS
Q3 2020 consolidated net income (including non-controlling interest) of $16.2 million; adjusted net income (as defined and reconciled below) of $7.1 million
Consolidated Adjusted EBITDA (as defined and reconciled below) of $40.4 million and cash available for distribution to Viper’s common limited partner units (as reconciled below) of $13.9 million
Previously announced Q3 2020 average production of 15,829 bo/d (26,409 boe/d), an increase of 10% from Q2 2020 average daily oil production and 16% year over year
Q3 2020 cash distribution of $0.10 per common unit, representing approximately 50% of cash available for distribution; $0.21 per unit of cash available for distribution implies a 12.0% annualized distributable cash flow yield based on the October 30, 2020 unit closing price of $7.01
Ended the third quarter with net debt of $599.1 million; total debt down $67.1 million since March 31, 2020, or a 10% reduction over the past six months
108 total gross (4.7 net 100% royalty interest) horizontal wells turned to production on Viper’s acreage during Q3 2020 with an average lateral length of 10,022 feet
Initiating average daily production guidance for Q4 2020 and Q1 2021 of 15,250 to 16,250 bo/d (25,500 to 27,000 boe/d)
Narrowing full year 2020 average production guidance to 15,750 to 16,000 bo/d (26,000 to 26,500 boe/d)
As of October 14, 2020, there were approximately 486 gross horizontal wells in the process of active development on Viper’s acreage, in which Viper expects to own an average 1.4% net royalty interest (6.6 net 100% royalty interest wells)
Approximately 431 gross (11.2 net 100% royalty interest) line-of-sight wells that are not currently in the process of active development, but for which Viper has visibility to the potential of future development in coming quarters, based on Diamondback’s current completion schedule and third party operators’ permits
Q2 2020 and Q3 2020 distributions reasonably estimated to not constitute dividends for U.S. federal income tax purposes; instead should generally constitute non-taxable reductions to the tax basis




The following information was filed by Viper Energy Partners Lp (VNOM) on Monday, November 2, 2020 as an 8K 2.02 statement, which is an earnings press release pertaining to results of operations and financial condition. It may be helpful to assess the quality of management by comparing the information in the press release to the information in the accompanying 10-Q Quarterly Report statement of earnings and operation as management may choose to highlight particular information in the press release.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2020
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-36505
 
Viper Energy Partners LP
(Exact Name of Registrant As Specified in Its Charter)
DE
46-5001985
(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification Number)
500 West Texas
Suite 1200
Midland,TX
79701
(Address of principal executive offices)
(Zip code)
(432) 221-7400
(Registrant's telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsVNOMThe Nasdaq Stock Market LLC
(NASDAQ Global Select Market)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One):
Large Accelerated FilerAccelerated Filer
Non-Accelerated FilerSmaller Reporting Company
Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    

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

As of October 30, 2020, the registrant had outstanding 67,862,281 common units representing limited partner interests and 90,709,946 Class B units representing limited partner interests.


VIPER ENERGY PARTNERS LP
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2020
TABLE OF CONTENTS
Page


i

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”):
BasinA large depression on the earth’s surface in which sediments accumulate.
Bbl or barrelOne stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOEOne barrel of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/dBOE per day.
British Thermal Unit or BtuThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CondensateLiquid hydrocarbons associated with the production of a primarily natural gas reserve.
Crude oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
FracturingThe process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
Horizontal wellsWells 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.
MBOEOne thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
McfOne thousand cubic feet of natural gas.
Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtuOne million British Thermal Units.
Net royalty acresGross acreage multiplied by the average royalty interest.
Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.
OperatorThe individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
ProspectA 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 reservesThe estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
ReservesThe estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
ReservoirA porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interestAn interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
WTIWest Texas Intermediate.


ii

GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report:
Diamondback
Diamondback Energy, Inc., a Delaware corporation.
Exchange Act
The Securities Exchange Act of 1934, as amended.
GAAP
Accounting principles generally accepted in the United States.
General Partner
Viper Energy Partners GP LLC, a Delaware limited liability company, and the General Partner of the Partnership.
IPO
The Partnership’s initial public offering.
LTIP
Viper Energy Partners LP Long Term Incentive Plan.
NYMEX
New York Mercantile Exchange.
Operating Company
Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy Partners LP.
Partnership
Viper Energy Partners LP, a Delaware limited partnership.
Partnership agreement
The first amended and restated agreement of limited partnership, dated June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the IPO.
SEC
United States Securities and Exchange Commission.
Securities Act
The Securities Act of 1933, as amended.
Wells Fargo
Wells Fargo Bank, National Association.

iii

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 under “Part II. Item 1A. Risk Factors” in this report, our Annual Report on Form 10-K for the year ended December 31, 2019 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of the Partnership and its consolidated subsidiary, Viper Energy Partners LLC (the “Operating Company”).

Forward-looking statements may include statements about:
the volatility of realized oil and natural gas prices and the extent and duration of price reductions and increased production by the Organization of the Petroleum Exporting Countries, or OPEC, members and other oil exporting nations;
the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic, or any government responses to such threat, occurrence or pandemic;
logistical challenges and the supply chain disruptions during the ongoing COVID-19 pandemic;
changes in general economic, business or industry conditions;
conditions in the capital, financial and credit markets;
conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;
U.S. and global economic conditions and political and economic developments, including the outcome of the recent U.S. presidential election and resulting energy and environmental policies;
our ability to execute our business and financial strategies;
the level of production on our properties;
regional supply and demand factors, delays, curtailments or interruptions of production, and any government order, rule or regulation that may impose production limits on properties in which we have mineral and royalty interest;
actions taken by third party operators on our mineral and royalty acreage;
our ability to replace our oil and natural gas reserves;
our ability to identify, complete and effectively integrate acquisitions of properties or businesses;
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;
iv

future distributions to eligible unitholders;
impact of potential impairment charges;
exploration and development drilling prospects, inventories, projects and programs;
operating hazards faced by our operators;
the ability of our operators to keep pace with technological advancements;
the effect of existing and future laws and government regulations;
civil unrest, terrorist attacks and cyber threats;
the effects of future litigation; and
certain other factors discussed elsewhere in this report.

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.
v

PART I. FINANCIAL INFORMATION


ITEM 1.     CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Viper Energy Partners LP
Condensed Consolidated Balance Sheets
(Unaudited)
September 30,December 31,
20202019
(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents$7,374 $3,602 
Royalty income receivable (net of allowance for credit losses)32,108 58,089 
Royalty income receivable—related party14,911 10,576 
Other current assets371 397 
Total current assets54,764 72,664 
Property:
Oil and natural gas interests, full cost method of accounting ($1,452,248 and $1,551,767 excluded from depletion at September 30, 2020 and December 31, 2019, respectively)
2,930,869 2,868,459 
Land5,688 5,688 
Accumulated depletion and impairment(398,678)(326,474)
Property, net2,537,879 2,547,673 
Deferred tax asset (net of allowance)— 142,466 
Other assets8,057 22,823 
Total assets$2,600,700 $2,785,626 
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable$95 $— 
Accounts payable—related party— 150 
Accrued liabilities20,831 13,282 
Derivative instruments23,263 — 
Total current liabilities44,189 13,432 
Long-term debt, net597,880 586,774 
Derivative instruments5,487 — 
Total liabilities647,556 600,206 
Commitments and contingencies (Note 12)
Unitholders’ equity:
General partner829 889 
Common units (67,850,632 units issued and outstanding as of September 30, 2020 and 67,805,707 units issued and outstanding as of December 31, 2019)
725,625 929,116 
Class B units (90,709,946 units issued and outstanding as of September 30, 2020 and December 31, 2019)
1,055 1,130 
Total Viper Energy Partners LP unitholders’ equity727,509 931,135 
Non-controlling interest1,225,635 1,254,285 
Total equity1,953,144 2,185,420 
Total liabilities and unitholders’ equity$2,600,700 $2,785,626 


See accompanying notes to condensed consolidated financial statements.
1

Viper Energy Partners LP
Condensed Consolidated Statements of Operations
(Unaudited)
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands, except per unit amounts)
Operating income:
Royalty income$62,584 $71,080 $171,857 $201,950 
Lease bonus income40 698 1,685 3,607 
Other operating income318 10 761 15 
Total operating income62,942 71,788 174,303 205,572 
Costs and expenses:
Production and ad valorem taxes5,049 4,731 14,306 12,812 
Depletion24,780 18,697 72,204 51,408 
General and administrative expenses1,811 1,805 6,160 5,223 
Total costs and expenses31,640 25,233 92,670 69,443 
Income from operations31,302 46,555 81,633 136,129 
Other income (expense):
Interest expense, net(8,238)(3,827)(24,870)(11,089)
Gain (loss) on derivative instruments, net(5,084)— (47,469)— 
Gain (loss) on revaluation of investment(1,984)336 (8,661)3,978 
Other income, net188 553 1,111 1,756 
Total other expense, net(15,118)(2,938)(79,889)(5,355)
Income (loss) before income taxes16,184 43,617 1,744 130,774 
Provision for (benefit from) income taxes— (7,480)142,466 (41,908)
Net income (loss)16,184 51,097 (140,722)172,682 
Net income (loss) attributable to non-controlling interest16,948 43,151 23,963 128,692 
Net income (loss) attributable to Viper Energy Partners LP$(764)$7,946 $(164,685)$43,990 
Net income (loss) attributable to common limited partner units:
Basic$(0.01)$0.13 $(2.43)$0.73 
Diluted$(0.01)$0.13 $(2.43)$0.73 
Weighted average number of common limited partner units outstanding:
Basic67,847 62,645 67,832 60,267 
Diluted67,847 62,678 67,832 60,296 














See accompanying notes to condensed consolidated financial statements.
2

Viper Energy Partners LP
Condensed Consolidated Statements of Changes to Unitholders' Equity
(Unaudited)

Limited PartnersGeneral PartnerNon-Controlling Interest
CommonClass B AmountAmount
UnitsAmountUnitsAmountTotal
(In thousands)
Balance at December 31, 201967,806 $929,116 90,710 $1,130 $889 $1,254,285 $2,185,420 
Unit-based compensation42 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 income (loss)— (142,169)— — — 18,319 (123,850)
Balance at March 31, 202067,831 756,408 90,710 1,105 869 1,231,785 1,990,167 
Unit-based compensation— 283 — — — — 283 
Distribution equivalent rights payments— (4)— — — — (4)
Distributions to public— (6,710)— — — — (6,710)
Distributions to Diamondback— (76)— (25)— (9,074)(9,175)
Distributions to General Partner— — — — (20)— (20)
Net income (loss)— (21,752)— — — (11,304)(33,056)
Balance at June 30, 202067,831 728,149 90,710 1,080 849 1,211,407 1,941,485 
Unit-based compensation20 275 — — — — 275 
Distribution equivalent rights payments— (2)— — — — (2)
Distributions to public— (2,013)— — — — (2,013)
Distributions to Diamondback— (19)— (25)— (2,720)(2,764)
Distributions to General Partner— — — (20)— (20)
Units repurchased for tax withholding— (1)— — — — (1)
Net income (loss)— (764)— — — 16,948 16,184 
Balance at September 30, 202067,851 $725,625 90,710 $1,055 $829 $1,225,635 $1,953,144 














See accompanying notes to condensed consolidated financial statements.
3

Viper Energy Partners LP
Condensed Consolidated Statements of Changes to Unitholders' Equity - Continued
(Unaudited)

Limited PartnersGeneral PartnerNon-Controlling Interest
CommonClass B AmountAmount
UnitsAmountUnitsAmountTotal
(In thousands)
Balance at December 31, 201851,654 $540,112 72,419 $990 $1,000 $694,940 $1,237,042 
Net proceeds from the issuance of common units - public10,925 340,648 — — — — 340,648 
Unit-based compensation60 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 (loss)— 33,779 — — — 40,532 74,311 
Balance at March 31, 201962,628 817,014 72,419 990 1,000 788,658 1,607,662 
Offering costs— (9)— — — — (9)
Unit-based compensation— 472 — — — — 472 
Distributions to public— (23,521)— — — — (23,521)
Distributions to Diamondback— (298)— — — (27,519)(27,817)
Distributions to General Partner— (20)— — — — (20)
Net income (loss)— 2,265 — — — 45,009 47,274 
Balance at June 30, 201962,628 795,903 72,419 990 1,000 806,148 1,604,041 
Unit-based compensation21 449 — — — — 449 
Distributions to public— (29,099)— — — — (29,099)
Distributions to Diamondback— (364)— — — (34,036)(34,400)
Distributions to General Partner— (20)— — — — (20)
Net income (loss)— 7,946 — — — 43,151 51,097 
Balance at September 30, 201962,649 $774,815 72,419 $990 $1,000 $815,263 $1,592,068 

















See accompanying notes to condensed consolidated financial statements.
4

Viper Energy Partners LP
Condensed Consolidated Statements of Cash Flows
(Unaudited)

Nine Months Ended September 30,
20202019
(In thousands)
Cash flows from operating activities:
Net income (loss)$(140,722)$172,682 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) income taxes142,466 (42,077)
Depletion72,204 51,408 
(Gain) loss on derivative instruments, net47,469 — 
Net cash payments on derivatives(18,718)— 
(Gain) loss on extinguishment of debt— 
(Gain) loss on revaluation of investment8,661 (3,978)
Amortization of debt issuance costs1,730 676 
Non-cash unit-based compensation945 1,326 
Changes in operating assets and liabilities:
Royalty income receivable25,981 (4,465)
Royalty income receivable—related party(4,335)(10,544)
Accounts payable and accrued liabilities7,644 (821)
Accounts payable—related party(150)— 
Income tax payable— 169 
Other current assets25 (148)
Net cash provided by (used in) operating activities143,206 164,228 
Cash flows from investing activities:
Acquisitions of oil and natural gas interests(64,508)(319,696)
Funds held in escrow— (7,500)
Proceeds from sale of assets2,098 — 
Proceeds from the sale of investments5,262 — 
Net cash provided by (used in) investing activities(57,148)(327,196)
Cash flows from financing activities:
Proceeds from borrowings under credit facility95,000 368,000 
Repayment on credit facility(65,000)(369,500)
Debt issuance costs(90)(349)
Repayment of senior notes(19,697)— 
Proceeds from public offerings— 340,860 
Public offering costs— (221)
Units purchased for tax withholding(384)(353)
Distributions to General Partner (60)(60)
Distributions to public (38,943)(78,590)
Distributions to Diamondback (53,112)(99,543)
Net cash provided by (used in) financing activities(82,286)160,244 
Net increase (decrease) in cash3,772 (2,724)
Cash and cash equivalents at beginning of period3,602 22,676 
Cash and cash equivalents at end of period$7,374 $19,952 
Supplemental disclosure of cash flow information:
Interest paid$19,196 $10,882 

See accompanying notes to condensed consolidated financial statements.
5

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 Partnership is currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian Basin and Eagle Ford Shale.

As of September 30, 2020, Viper Energy Partners GP LLC (the “General Partner”), held a 100% general partner interest in the Partnership and Diamondback Energy, Inc. (“Diamondback”) beneficially owned an approximate 58% of the Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner.

Basis of Presentation

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

These condensed consolidated financial statements have been prepared by the Partnership without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This report should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2019, which contains a summary of the Partnership’s significant accounting policies and other disclosures.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Making accurate estimates and assumptions is particularly difficult as the oil and gas industry experiences challenges resulting from negative pricing pressure from the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets. Many companies in the oil and natural gas industry have changed near term business plans in response to changing market conditions. The aforementioned circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts.

The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests, the recoverability of costs of unevaluated properties, fair value estimates of commodity derivatives, unit–based compensation and estimate of income taxes.


6

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


Accounts Receivable

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

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 collection is deemed doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Partnership determines its allowance by considering a number of factors, including the Partnership’s previous loss history, the debtor’s current ability to pay its obligation to the Partnership, the condition of the general economy and the industry as a whole. The Partnership writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. The adoption of ASU 2016-13 did not result in a material change to the Partnership’s allowance, and no cumulative-effect adjustment was made to beginning unitholders’ equity. At September 30, 2020, the Partnership recorded an immaterial allowance for expected losses and did not record such an allowance at December 31, 2019.

Derivative Instruments

The Partnership is required to recognize its derivative instruments on the condensed consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the condensed consolidated statements of operations.

Accrued Liabilities

Accrued liabilities consist of the following:
September 30,December 31,
20202019
(In thousands)
Interest payable$10,771 $6,718 
Ad valorem taxes payable5,186 5,632 
Derivatives instruments payable4,731 — 
Other143 932 
Total accrued liabilities$20,831 $13,282 

Non-controlling Interest

Non-controlling interest in the accompanying condensed consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. When Diamondback’s relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder’s equity, tax effected, will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest.

In the first quarter of 2019, the Partnership recorded an adjustment to non-controlling interest of $90.1 million, common unitholder equity of $(71.2) million, and deferred tax asset of $18.9 million to reflect the ownership structure that was effective at March 31, 2019. The adjustment had no impact on earnings. See Note 7 - Unitholders' Equity and Partnership Distributions for further discussion of change in ownership.
7

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


Recent Accounting Pronouncements

The Partnership considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Partnership’s analysis of the effects on its financial statements:
StandardDescriptionDate of AdoptionEffect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses”
This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.
Q1 2020
The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.

Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.Q1 2021This 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 at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

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

Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands)
Oil income$53,595 $64,829 $153,412 $182,679 
Natural gas income3,331 2,181 4,909 4,946 
Natural gas liquids income5,658 4,070 13,536 14,325 
Total royalty income$62,584 $71,080 $171,857 $201,950 

4.    ACQUISITIONS

2020 Activity

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

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


2019 Activity

Drop-Down Acquisition

On October 1, 2019, we completed the acquisition of certain mineral and royalty interests from subsidiaries of Diamondback for approximately 18.3 million of its newly-issued Class B units, approximately 18.3 million newly-issued units of the Operating Company with a fair value of $497.2 million and $190.2 million in cash, after giving effect to closing adjustments for net title benefits (the ‘‘Drop-Down Acquisition’’). The mineral and royalty interests acquired in the Drop-Down Acquisition represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by Diamondback, and have an average net royalty interest of approximately 3.2% (the ‘‘Drop-Down Assets’’). The Partnership completed the acquisition on October 1, 2019 and funded the cash portion of the purchase price for the Drop-Down Assets through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility.

Santa Elena Acquisition

On October 31, 2019, the Partnership completed the acquisition of certain mineral and royalty interests from Santa Elena (the ‘‘Santa Elena Acquisition’’), which assets were immediately contributed by the Partnership to the Operating Company. The assets acquired in the Santa Elena Acquisition represent approximately 1,366 net royalty acres across the Midland Basin with an average net royalty interest of approximately 5.6% and are primarily operated by Diamondback in Glasscock and Martin counties (the ‘‘Santa Elena Assets’’).

At closing, the Partnership issued to Santa Elena approximately 5.2 million common units representing limited partner interests in the Partnership as consideration for the Santa Elena Assets, and the Operating Company issued to the Partnership approximately 5.2 million new units of the Operating Company with a fair value of $124.0 million.

Other Recent Acquisitions

In addition, during the year ended December 31, 2019, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests representing 136,012 gross (2,607 net royalty) acres for an aggregate of approximately $343.7 million. The Partnership funded these acquisitions with cash on hand, a portion of the net proceeds from its first quarter 2019 offering of common units and borrowings under the Operating Company’s revolving credit facility.

5.    OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:
September 30,December 31,
20202019
(In thousands)
Oil and natural gas interests:
Subject to depletion$1,478,621 $1,316,692 
Not subject to depletion1,452,248 1,551,767 
Gross oil and natural gas interests2,930,869 2,868,459 
Accumulated depletion and impairment(398,678)(326,474)
Oil and natural gas interests, net2,532,191 2,541,985 
Land5,688 5,688 
Property, net of accumulated depletion and impairment$2,537,879 $2,547,673 

As of September 30, 2020 and December 31, 2019, the Partnership had mineral and royalty interests representing 24,696 and 24,304 net royalty acres, respectively.


9

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


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. After performing the ceiling test for the quarter ended September 30, 2020, the Partnership was not required to record an impairment. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, the Partnership will have write-downs in subsequent quarters, which may be material.

6.    DEBT

Long-term debt consisted of the following as of the dates indicated:
September 30,December 31,
20202019
(In thousands)
5.375% Senior Notes due 2027
$479,938 $500,000 
Revolving credit facility126,500 96,500 
Unamortized debt issuance costs(2,133)(2,458)
Unamortized discount(6,425)(7,268)
Total long-term debt$597,880 $586,774 

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. During the three and nine months ended September 30, 2020, the Partnership repurchased $6.0 million and $20.1 million, respectively, of the outstanding principal of the Notes at a cash price ranging from 97.5% to 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt. As of September 30, 2020, the remaining outstanding principal amount of the Notes totaled $479.9 million and will mature on November 1, 2027.

The Operating Company’s Revolving Credit Facility

On July 20, 2018, the Partnership, as guarantor, entered into an amended and restated credit agreement with the Operating Company, as borrower, Wells Fargo National Bank (“Wells Fargo”), as administrative agent, and the other lenders. The credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on the Operating Company’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November. 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. The Operating Company’s borrowing base was reduced from $775.0 million to $580.0 million during the regularly scheduled (semi-annual) spring 2020 redetermination in the second quarter of 2020, and is expected to be reaffirmed at $580.0 million by the lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of September 30, 2020, there were $126.5 million of outstanding borrowings and $453.5 million available for future borrowings under the Operating Company’s revolving credit facility. During the three and nine months ended September 30, 2020, the weighted average interest rates on the Operating Company’s revolving credit facility were 2.14% and 2.66%, respectively. The revolving credit facility will mature on November 1, 2022.

As of September 30, 2020, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement.


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


7.    UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has general partner and limited partner units. At September 30, 2020, the Partnership had a total of 67,850,632 common units issued and outstanding and 90,709,946 Class B units issued and outstanding, of which 731,500 common units and 90,709,946 Class B units were beneficially owned by Diamondback, representing approximately 58% of the Partnership’s total units outstanding. Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 57% non-controlling ownership interest in the Operating Company. The Operating Company units and the Partnership’s Class B units beneficially owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

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 its revolving credit facility and finance acquisitions during the period.

The following table summarizes the ownership interest in subsidiary changes during the period:

Nine Months Ended September 30, 2019
(In thousands)
Net income (loss) attributable to the Partnership$43,990 
Change in ownership of consolidated subsidiaries due to purchase of subsidiary shares in 2019 offering(71,195)
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest$(27,205)

There were no changes in ownership of consolidated subsidiaries during the three and nine months ended September 30, 2020 and the three months ended September 30, 2019.

Beginning with the first quarter of 2020, the board of directors of the General Partner revised the distribution policy pursuant to which the Operating Company distributed 25% of the available cash in the first and second quarters of 2020 to its unitholders. The distribution policy was further revised in October 2020 to provide for the distribution of 50% of the available cash beginning with the third quarter of 2020 to its unitholders (including Diamondback and the Partnership). The Partnership in turn distributes all of the available cash it receives from the Operating Company to its common unitholders. The Partnership’s available cash, and the available cash of the Operating Company, for each quarter is determined by the board of directors of the General Partner following the end of such quarter. The Operating Company’s available cash generally equals its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations, fixed charges and reserves for future operating or capital needs that the board of directors of the General Partner deems necessary or appropriate, if any. The Partnership’s available cash for each quarter generally equals its Adjusted EBITDA (which is the Partnership’s proportional share of the available cash of the Operating Company for the quarter), less cash needed for the payment of income taxes by it, if any, and the preferred distribution. Immediately prior to the revisions to the distribution policy described above, the Operating Company’s policy was to distribute all of its available cash quarterly to its unitholders. The distribution policy was changed to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet.

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


11

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


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 UnitDeclaration DateUnitholder Record DatePayment Date
Q4 2019$0.45 February 7, 2020February 21, 2020February 28, 2020
Q1 2020$0.10 April 30, 2020May 14, 2020May 21, 2020
Q2 2020$0.03 July 29, 2020August 13, 2020August 20, 2020

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

Amendment to LLC Agreement - Tax Allocation

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

8.    EARNINGS PER COMMON UNIT

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

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

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

A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands, except per unit amounts)
Net income (loss) attributable to the period$(764)$7,946 $(164,685)$43,990 
Less: net gain (loss) allocated to participating securities(1)
(2)(27)(26)(90)
Net income (loss) attributable to common unitholders$(766)$7,919 $(164,711)$43,900 
Weighted average common units outstanding:
Basic weighted average common units outstanding67,847 62,645 67,832 60,267 
Effect of dilutive securities:
Potential common units issuable(2)
— 33 — 29 
Diluted weighted average common units outstanding67,847 62,678 67,832 60,296 
Net income (loss) per common unit, basic$(0.01)$0.13 $(2.43)$0.73 
Net income (loss) per common unit, diluted$(0.01)$0.13 $(2.43)$0.73 
(1)    Distribution equivalent rights granted to employees are considered participating securities.
(2) For the three and nine months ended September 30, 2020, no potential common units were included in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive under the treasury stock method for the periods presented but could potentially dilute basic earnings per common unit in future periods.
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Viper Energy Partners LP
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)



9.    INCOME TAXES

The Partnership’s effective income tax rates were 0% and (17.1)% for the three months ended September 30, 2020 and 2019, respectively. The Partnership’s effective income tax rate exceeded 100% for the nine months ended September 30, 2020 due to the impact of recording a valuation allowance as discussed further below, and was (32.0)% for the nine months ended September 30, 2019. Total income tax expense for the three and nine months ended September 30, 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 and nine months ended September 30, 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 election to be treated as a corporation for U.S. federal income tax purposes effective May 10, 2018.

For the nine months ended September 30, 2020, the Partnership’s total income tax provision includes a discrete income tax expense of approximately $142.5 million recorded for the three months ended March 31, 2020, related to application of a full valuation allowance on the Partnership’s beginning-of-the-year deferred tax assets, which consist primarily 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 pre-tax loss attributable to the Partnership. The determination to record a valuation allowance as of March 31, 2020 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 application of a full valuation allowance against its deferred tax assets as of March 31, 2020, June 30, 2020 and September 30, 2020.

For the nine months ended September 30, 2019, the Partnership recorded a discrete income tax benefit of approximately $42.4 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, the Partnership revised its estimate of the difference between its tax basis and its basis for financial accounting purposes in the Operating Company on the date of the tax status change, resulting in deferred income tax benefit of $42.4 million included in the Partnership’s income tax provision for the nine months ended September 30, 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.

10.    DERIVATIVES

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

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


Commodity Contracts

The Partnership uses fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. With respect to the Partnership’s fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to the Partnership if the settlement price for any settlement period is less than the swap or basis price, and the Partnership is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap or basis price. The Partnership has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price.

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

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

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

As of September 30, 2020, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
SwapsCollarsCalls
Settlement MonthSettlement YearType of ContractBbls/Mcf Per DayIndexWeighted Average DifferentialWeighted Average Fixed PriceWeighted Average Floor PriceWeighted Average Ceiling PriceStrike Price
OIL
Oct. - Dec.2020Swaps1,000WTI Cushing$—$27.45$—$—$—
Oct. - Dec.2020Basis Swaps4,000
WTI Cushing(2)
$(2.60)$—$—$—$—
Oct. - Dec.2020Collars14,000WTI Cushing$—$—$28.86$32.33$—
Jan. - Dec.2021Collars10,000WTI Cushing$—$—$30.00$43.05$—
Oct. - Dec.2020
Calls(1)
8,000WTI Cushing$—$—$—$—$45.00
NATURAL GAS
Oct. - Dec.2020Basis Swaps25,000
Waha Hub(2)
$(2.07)$—$—$—$—
(1) Includes a deferred premium at a weighted-average price of $1.89/Bbl and a strike price of $45.00/Bbl.
(2) 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. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.


14

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


Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 11—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments included in the condensed consolidated statements of operations:
Three Months Ended September 30, 2020Nine Months Ended September 30,
2020201920202019
(In thousands)
Gain (loss) on derivative instruments$(5,084)$— $(47,469)$— 
Net cash payments on derivatives$(16,164)$— $(18,718)$— 
11.    FAIR VALUE MEASUREMENTS

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

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Partnership’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Partnership uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.
Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

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

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

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

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 investment. The Partnership measures its investment utilizing the fair value option, and as such the investment is classified as Level 1 in the fair value hierarchy, and is included in other assets on the condensed consolidated balance sheets. The fair values of the Partnership’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.


15

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


The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Partnership’s condensed consolidated balance sheets as of September 30, 2020 and December 31, 2019. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

As of September 30, 2020
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In thousands)
Assets:
Current:
Derivative instruments$— $3,856 $— $3,856 $3,856 $— 
Non-current:
Investment$5,434 $— $— $5,434 $— $5,434 
Derivative instruments$— $2,347 $— $2,347 $2,347 $— 
Liabilities:
Current:
Derivative instruments$— $27,119 $— $27,119 $3,856 $23,263 
Non-current:
Derivative instruments$— $7,834 $— $7,834 $2,347 $5,487 

As of December 31, 2019
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In thousands)
Assets:
Non-current:
Investment$19,357 $— $— $19,357 $— $19,357 

The Partnership did not have any derivatives prior to February 2020.

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:
September 30, 2020December 31, 2019
Carrying ValueFair ValueCarrying ValueFair Value
(In thousands)
Debt:
Revolving credit facility $126,500 $126,500 $96,500 $96,500 
5.375% Senior Notes due 2027(1)
$471,380 $476,636 $490,274 $521,100 
(1) The carrying value includes associated deferred loan costs and any discount.

16

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


The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was determined using the September 30, 2020 quoted market price, a Level 1 classification in the fair value hierarchy.

Fair Value of Financial Assets

The Partnership has other financial instruments consisting of cash and cash equivalents, royalty income receivable, other current assets, accounts payable and accrued liabilities. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.

12.    COMMITMENTS AND CONTINGENCIES

The Partnership is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry. These proceedings, disputes and claims may include differing interpretations as to the prices at which crude oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, title claims, environmental issues and other matters. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Partnership, cannot be predicted with certainty, the Partnership’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Partnership’s assessment. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

13.    SUBSEQUENT EVENTS

Cash Distribution

On October 28, 2020, the board of directors of the General Partner approved a cash distribution for the third quarter of 2020 of $0.10 per common unit, payable on November 19, 2020, to eligible unitholders of record at the close of business on November 12, 2020.

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ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 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. We are currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. We operate in one reportable segment. Since May 10, 2018, we have been treated as a corporation for U.S. federal income tax purposes.

As of September 30, 2020, our general partner held a 100% general partner interest in us, and Diamondback owned 731,500 of our common units and beneficially owned 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.

Recent Developments

COVID-19 and Collapse in Commodity Prices

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

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

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

Based on the results of the quarterly ceiling test, we were not required to record an impairment on our proved oil and natural gas interests for the quarter ended September 30, 2020. If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices fail to stabilize or decrease further, our production, proved reserves and cash flows will be adversely impacted. Our business may be also further adversely impacted by any pipeline capacity and storage constraints.


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Given the dynamic nature of the events described above, we cannot reasonably estimate the period of time that the ongoing COVID-19 pandemic, the depressed commodity prices, the reduced demand for oil and the adverse macroeconomic will persist, the full extent of the impact they will have on our industry and our business, financial condition or cash flows, or the pace or extent of any subsequent recovery.

Acquisitions and Divestitures Update

We did not complete any acquisitions during the third quarter of 2020 and divested an insignificant amount of acreage, leaving our footprint of mineral and royalty interests at a total of 24,696 royalty acres at September 30, 2020.

Cash Distribution Update

On October 28, 2020, the board of directors of our general partner declared a cash distribution for the three months ended September 30, 2020 of $0.10 per common unit, increasing our distribution for the third quarter of 2020 to 50% of cash available for distribution, up from 25% in the second quarter of 2020. The distribution is payable on November 19, 2020 to eligible common unitholders of record at the close of business on November 12, 2020. With net debt decreasing in the third quarter of 2020 from peak levels due to strong free cash flow generation, as well as an improved forward outlook for production, realized pricing and free cash flow yield, driven primarily by Diamondback’s anticipated development plan and benefiting from our hedging arrangements rolling off in 2021, we expect to continue to increase our return on capital to unitholders in future quarters.

Production and Operational Update

We produced a strong third quarter of 2020, reflecting a 10% increase in oil production quarter over quarter as commodity prices improved from historic lows witnessed in the first half of 2020 and many of our operators returned previously curtailed production to market and resumed completion activity on our mineral and royalty acreage. As a result, during the third quarter of 2020, we estimate that 108 gross (4.7 net 100% royalty interest) horizontal wells, in which we have an average royalty interest of 4.3% were turned to production on our existing acreage position with an average lateral length of 10,022 feet. Of these 108 gross wells, Diamondback is the operator of 38, in which we have an average royalty interest of 9.9%, and the remaining 70 gross wells, in which we have an average royalty interest of 1.3%, are operated by third parties. With production already within the high end of our previously guided range, we expect that we will exit 2020 with a strong production rate, positioning us well to deliver robust free cash flow in 2021.

Despite the ongoing challenging commodity pricing environment, there continues to be active development across our asset base, as there are currently 21 gross rigs operating on our mineral and royalty acreage, four of which are operated by Diamondback. Although visibility into third-party operators’ anticipated activity levels has increased in recent months, it remains limited and near-term activity is expected to be driven primarily by Diamondback operations. Diamondback brought back three completion crews during the third quarter of 2020 and resumed completion activity in areas where we have a significant mineral and royalty interest. Diamondback has announce that its’ forward plan will continue to focus on areas where we have a high royalty interest, showcasing the differentiated relationship between the two companies as we navigate this severe industry downturn.


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The following table summarizes our gross well information as of October 14, 2020:
As of October 14, 2020
Diamondback OperatedThird Party OperatedTotal
Horizontal wells turned to production:
Gross wells3870108
Net 100% royalty interest wells3.80.94.7
Average percent net royalty interest9.9 %1.3 %4.3 %
Horizontal producing well count:
Gross wells1,1213,4274,548
Net 100% royalty interest wells88.252.6140.8
Average percent net royalty interest7.9 %1.5 %3.1 %
Horizontal active development well count(1):
Gross wells71415486
Net 100% royalty interest wells3.53.16.6
Average percent net royalty interest5.0 %0.7 %1.4 %
Line of sight wells(2):
Gross wells110321431
Net 100% royalty interest wells7.43.911.2
Average percent net royalty interest6.7 %1.2 %2.6 %

(1) The total 486 gross wells currently in the process of active development are those wells that have been spud and are expected to be turned to production within approximately the next six to eight months.
(2) The total 431 line-of-sight wells are those that are not currently in the process of active development, but for which we have reason to believe that they will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our royalty acreage does not ensure that those wells will be turned to production given the current depressed oil prices.

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Results of Operations

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

Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
 (In thousands)
Operating Results:
Operating income:
Royalty income$62,584 $71,080 $171,857 $201,950 
Lease bonus income40 698 1,685 3,607 
Other operating income318 10 761 15 
Total operating income62,942 71,788 174,303 205,572 
Costs and expenses:
Production and ad valorem taxes5,049 4,731 14,306 12,812 
Depletion24,780 18,697 72,204 51,408 
General and administrative expenses1,811 1,805 6,160 5,223 
Total costs and expenses31,640 25,233 92,670 69,443 
Income from operations31,302 46,555 81,633 136,129 
Other income (expense):
Interest expense, net(8,238)(3,827)(24,870)(11,089)
Gain (loss) on derivative instruments, net(5,084)— (47,469)— 
Gain (loss) on revaluation of investment(1,984)336 (8,661)3,978 
Other income, net188 553 1,111 1,756 
Total other expense, net(15,118)(2,938)(79,889)(5,355)
Income (loss) before income taxes16,184 43,617 1,744 130,774 
Provision for (benefit from) income taxes— (7,480)142,466 (41,908)
Net income (loss)16,184 51,097 (140,722)172,682 
Net income (loss) attributable to non-controlling interest16,948 43,151 23,963 128,692 
Net income (loss) attributable to Viper Energy Partners LP$(764)$7,946 $(164,685)$43,990 
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Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
 
Production Data:
Oil (MBbls)1,456 1,258 4,359 3,607 
Natural gas (MMcf)3,111 1,710 8,454 5,222 
Natural gas liquids (MBbls)455 413 1,402 976 
Combined volumes (MBOE)(1)
2,430 1,956 7,169 5,454 
Average daily oil volumes (BO/d)(2)
15,829 13,674 15,907 13,213 
Average daily combined volumes (BOE/d)(2)
26,409 21,266 26,165 19,977 
Average sales prices(2):
Oil ($/Bbl)$36.80 $51.53 $35.20 $50.65 
Natural gas ($/Mcf)(3)
$1.07 $1.28 $0.58 $0.95 
Natural gas liquids ($/Bbl)$12.44 $9.84 $9.66 $14.67 
Combined ($/BOE)$25.76 $36.33 $23.97 $37.03 
Oil, hedged ($/Bbl)(4)
$27.65 $51.53 $32.56 $50.65 
Natural gas, hedged ($/Mcf)(4)
$0.16 $1.28 $(0.27)$0.95 
Natural gas liquids ($/Bbl)(4)
$12.44 $9.84 $9.66 $14.67 
Combined price, hedged ($/BOE)(4)
$19.11 $36.33 $21.36 $37.03 
Average costs ($/BOE):
Production and ad valorem taxes$2.08 $2.42 $2.00 $2.35 
General and administrative - cash component(5)
0.63 0.69 0.73 0.71 
Total operating expense - cash$2.71 $3.11 $2.73 $3.06 
General and administrative - non-cash stock compensation expense$0.11 $0.23 $0.13 $0.24 
Interest expense, net$3.39 $1.96 $3.47 $2.03 
Depletion$10.20 $9.56 $10.07 $9.43 
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)Average daily volumes and average sales prices presented are based on actual production volumes and not calculated utilizing the rounded production volumes presented in the table above.
(3)The average realized price of natural gas was calculated in accordance with the pricing terms under our operators’ natural gas delivery contracts, which are generally tied to the NYMEX price quoted at Henry Hub. Actual volumetric prices realized from the sale of natural gas, however, differ from the quoted NYMEX price as a result of quality and location differentials. During the third quarter of 2020, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(0.68) relative to the NYMEX price quoted at Henry Hub. Our operators may have varying terms under which they sell their natural gas, but we are primarily impacted by location differences resulting from supply and demand imbalances and limited takeaway capacity within the Permian Basin.
(4)Hedged prices reflect the impact of cash settlements on our matured commodity derivative transactions on our average sales prices. We did not have any derivative contracts prior to February of 2020.
(5)Excludes non-cash stock compensation for the respective periods presented.


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Comparison of the Three Months Ended September 30, 2020 and 2019 and Nine Months Ended September 30, 2020 and 2019

Royalty Income

Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes.

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

Three Months Ended September 30, 2020 Compared to 2019
Nine Months Ended September 30, 2020 Compared to 2019
Change in prices
Production volumes(1)
Total net dollar effect of changeChange in prices
Production volumes(1)
Total net dollar effect of change
(In thousands)
Effect of changes in price:
Oil$(14.73)1,456 $(21,451)$(15.45)4,359 $(67,327)
Natural gas$(0.21)3,111 (636)$(0.37)8,454 (3,099)
Natural gas liquids$2.60 455 1,179 $(5.01)1,402 (7,030)
Total income due to change in price$(20,908)$(77,456)
Change in production volumes(1)
Prior period average pricesTotal net dollar effect of change
Change in production volumes(1)
Prior period average pricesTotal net dollar effect of change
(In thousands)
Effect of changes in production volumes:
Oil198 $51.53 $10,217 752 $50.65 $38,060 
Natural gas1,401 $1.28 1,786 3,232 $0.95 3,062 
Natural gas liquids42 $9.84 409 426 $14.67 6,241 
Total income due to change in production volumes12,412 47,363 
Total change in income$(8,496)$(30,093)
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

The impact of the decrease in average prices received during the three and nine months ended September 30, 2020 as compared to the same periods in 2019 was partially offset by a 24% and 31% increase in combined volumes sold by our operators as compared to the three and nine months ended September 30, 2019, respectively.


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Production and Ad Valorem Taxes

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

Three Months Ended September 30,
20202019
Amount
(In thousands)
Per BOEPercentage of Royalty IncomeAmount
(In thousands)
Per BOEPercentage of Royalty Income
Production taxes$3,106 $1.28 5.0 %$3,455 $1.77 4.9 %
Ad valorem taxes1,943 0.80 3.1 1,276 0.65 1.8 
Total production and ad valorem taxes$5,049 $2.08 8.1 %$4,731 $2.42 6.7 %

Nine Months Ended September 30,
20202019
Amount
(In thousands)
Per BOEPercentage of Royalty IncomeAmount
(In thousands)
Per BOEPercentage of Royalty Income
Production taxes$8,373 $1.17 4.9 %$9,671 $1.78 4.8 %
Ad valorem taxes5,933 0.83 3.4 3,141 0.57 1.5 
Total production and ad valorem taxes$14,306 $2.00 8.3 %$12,812 $2.35 6.3 %

Production taxes as a percentage of royalty income for the three months ended September 30, 2020 compared to the three months ended September 30, 2019 and the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 remained relatively flat. Ad valorem taxes as a percentage of royalty income for these same periods in 2020 compared to 2019 increased due to an increase in the valuation of oil and natural gas interests period over period primarily due to acquisitions and drilling activity, while royalty income declined due to lower prices.

Depletion

The $6.1 million, or 33%, increase in depletion expense for the three months ended September 30, 2020 compared to the same period in 2019 was due primarily to an increase in the depletion rate to $10.20 for the three months ended September 30, 2020 compared to $9.56 for the three months ended September 30, 2019, which largely resulted from higher production levels and an increase in net book value on new reserves added to the depletion base.

The $20.8 million, or 40%, increase in depletion expense for the nine months ended September 30, 2020 compared to the same period in 2019 was due primarily to an increase in the depletion rate to $10.07 for the nine months ended September 30, 2020 compared to $9.43 for the nine months ended September 30, 2019, which largely resulted from higher production levels and an increase in net book value on new reserves added to the depletion base.

General and Administrative Expenses

General and administrative expenses primarily reflect costs associated with being a publicly traded limited partnership, unit-based compensation and amounts reimbursed to our general partner under our partnership agreement. General and administrative expenses were flat for the three months ended September 30, 2020 and 2019. For the nine months ended September 30, 2020 and 2019, we incurred general and administrative expenses of $6.2 million and $5.2 million, respectively. The increase of $1.0 million during the nine months ended September 30, 2020 was primarily due to increases in amounts allocated from our general partner under our partnership agreement, higher software license fees, bad debt expense and higher legal expenses in 2020. These increases were partially offset by decreases in partnership tax compliance and K-1 preparation fees and unit-based compensation.


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Net Interest Expense

Net interest expense for the three months ended September 30, 2020 and 2019 was $8.2 million and $3.8 million, respectively. The increase of $4.4 million was due primarily to the interest incurred on the Notes which were issued in October 2019.

Net interest expense for the nine months ended September 30, 2020 and 2019 was $24.9 million and $11.1 million, respectively. The increase of $13.8 million was due to increased borrowings and a higher interest rate during 2020 compared to 2019, as a result of issuing the Notes during the fourth quarter of 2019. This increase was partially offset by repayments of the borrowings under the Operating Company’s revolving credit facility.

Derivative Instruments

We recorded a loss on derivative instruments for the three and nine months ended September 30, 2020 of $5.1 million and $47.5 million, respectively, which includes cash payments of $16.2 million and $18.7 million on settlements of commodity derivative contracts during the respective periods. We had no derivative instruments during the three and nine months ended September 30, 2019. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our condensed consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.”

Provision for (Benefit from) Income Taxes

We did not record an income tax benefit or expense for the three months ended September 30, 2020 due to maintaining a full valuation allowance against our deferred tax assets and recorded an income tax benefit of $7.5 million for the three months ended September 30, 2019.

We recorded income tax expense of $142.5 million and income tax benefit of $41.9 million for the nine months ended September 30, 2020 and 2019, respectively. The change in our income tax provision was primarily due to the application of a valuation allowance on our deferred tax assets during the nine months ended September 30, 2020, and the revision during the nine months ended September 30, 2019 of estimated deferred taxes recognized as a result of our change in federal income tax status. The total income tax provision for the nine months ended September 30, 2020 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to the impact of recording a valuation allowance on our deferred tax assets and net income attributable to the non-controlling interest. See Note 9—Income Taxes for further details.

Non-GAAP Financial Measures

Adjusted EBITDA

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

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

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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 and cash available for distribution to net income (loss), our most directly comparable GAAP financial measure for the periods indicated:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In thousands)
Net income (loss)$16,184 $51,097 $(140,722)$172,682 
Interest expense, net8,238 3,827 24,870 11,089 
Non-cash unit-based compensation expense275 449 945 1,326 
Depletion24,780 18,697 72,204 51,408 
(Gain) loss on revaluation of investment1,984 (336)8,661 (3,978)
Non-cash (gain) loss on derivative instruments(11,080)— 28,751 — 
(Gain) loss on extinguishment of debt20 — — 
Provision for (benefit from) income taxes— (7,480)142,466 (41,908)
Consolidated Adjusted EBITDA40,401 66,254 137,181 190,619 
Less: Adjusted EBITDA attributable to non-controlling interest(1)
23,113 35,525 78,492 102,216 
Adjusted EBITDA attributable to Viper Energy Partners LP$17,288 $30,729 $58,689 $88,403 
Adjustments to reconcile Adjusted EBITDA to cash available for distribution:
Income taxes payable$— $(61)— $(320)
Debt service, contractual obligations, fixed charges and reserves(3,297)(1,670)(9,941)(5,021)
Units repurchased for tax withholding(1)—