KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ~~PARTNERS’ CAPITAL AND PREDECESSOR MEMBERS’~~UNITHOLDERS’ EQUITY – (Continued)

(Unaudited)

Units

Total
Members' equity - December 31, 2016 (Predecessor)

604,137

$
8,631,862

Unit-based compensation

—

50,422

Net loss

—

(496,856)

Transfer of membership units to Rivercrest Royalties Holdings, LLC

(604,137)

(98,988)

Partners' capital - February 8, 2017 (Partnership)

—

8,086,440

Common units issued to Predecessor in exchange for oil and natural gas properties

1,191,974

—

Common units issued to contributors in exchange for oil and natural gas properties

9,390,734

169,033,212

Common units sold to public

5,750,000

103,500,000

Underwriting discount and structuring fee incurred at initial public offering

—

(7,245,000)

Distributions to unitholders

—

(8,705,333)

Unit-based compensation

177,091

569,889

Net income

—

653,898

Partners' capital - September 30, 2017

16,509,799

$
265,893,106


	Nine Months Ended September 30, 2019
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Balance at January 1, 2019		18,056,487	$	299,821,901		19,453,258	$	972,663	$	291,932,233	$	592,726,797
Units issued for Phillips Acquisition		—		—		9,400,000		470,000		171,550,000		172,020,000
Conversion of Class B units to common units		1,438,916		23,507,402		(1,438,916)		(71,946)		(23,507,402)		(71,946)
Unit-based compensation		—		1,770,410		—		—		—		1,770,410
Distributions to unitholders		—		(7,798,161)		—		—		(7,205,737)		(15,003,898)
Distribution and accretion on Series A preferred units		—		(1,441,938)		—		—		(2,027,646)		(3,469,584)
Distribution on Class B units		—		(23,814)		—		—		—		(23,814)
Net loss		—		(2,221,500)		—		—		(3,123,863)		(5,345,363)
Balance at March 31, 2019		19,495,403		313,614,300		27,414,342		1,370,717		427,617,585		742,602,602
Conversion of Class B units to common units		3,600,000		63,540,000		(3,600,000)		(180,000)		(63,540,000)		(180,000)
Restricted units used for tax withholding		(1,268)		(21,036)		—		—		—		(21,036)
Unit-based compensation		—		2,112,764		—		—		—		2,112,764
Distributions to unitholders		—		(8,545,299)		—		—		(8,811,307)		(17,356,606)
Distribution and accretion on Series A preferred units		—		(1,708,157)		—		—		(1,761,427)		(3,469,584)
Distribution on Class B units		—		(23,814)		—		—		—		(23,814)
Net loss		—		(10,026,403)		—		—		(10,339,084)		(20,365,487)
Balance at June 30, 2019		23,094,135		358,942,355		23,814,342		1,190,717		343,165,767		703,298,839
Conversion of Class B units to common units		426,084		6,641,087		(426,084)		(21,304)		(6,641,087)		(21,304)
Unit-based compensation		—		1,809,752		—		—		—		1,809,752
Distributions to unitholders		—		(9,162,713)		—		—		(9,633,877)		(18,796,590)
Distribution and accretion on Series A preferred units		—		(1,739,672)		—		—		(1,729,912)		(3,469,584)
Distribution on Class B units		—		(23,414)		—		—		—		(23,414)
Net loss		—		(14,497,965)		—		—		(14,416,623)		(28,914,588)
Balance at September 30, 2019		23,520,219	$	341,969,430		23,388,258	$	1,169,413	$	310,744,268	$	653,883,111

The accompanying notes are an integral part of these condensed consolidated financial statements.

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

~~(Unaudited)~~

Partnership

Predecessor

Period from February 8, 2017 to September 30,

Period from January 1, 2017 to February 7,

Nine Months Ended September 30,


2017


2017

2016
CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss)

$
653,898

$
(496,856)

$
(6,018,014)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion and accretion expense

11,156,292

113,639

1,244,023
Impairment of oil and natural gas properties

—

—

4,992,897
Amortization of loan origination costs

41,667

4,241

34,245
Amortization of tenant improvement allowance

—

(2,864)

(25,777)
Unit-based compensation

569,889

50,422

453,795
Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

(496,886)

14,551

11,258
Other current assets

(258,785)

333,056

1,246,269
Accounts payable

152,569

247,972

(1,071,453)
Other current liabilities

2,146,834

(77,442)

89,550
Net cash provided by operating activities

13,965,478

186,719

956,793
CASH FLOWS FROM INVESTING ACTIVITIES

Purchases of property and equipment

(57,592)

—

(18,016)
Deposits on oil and natural gas properties

(3,949,000)

—

—
Purchase of oil and natural gas properties

(113,183,664)

(523)

(75,883)
Net cash used in investing activities

(117,190,256)

(523)

(93,899)
CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from initial public offering

96,255,000

—

—
Distributions to unitholders

(8,705,333)

—

—
Borrowings on long-term debt

22,214,090

—

—
Repayments on long-term debt

—

—

(550,000)
Payment of loan origination costs

(312,500)

—

(13,000)
Net cash provided by (used in) financing activities

109,451,257

—

(563,000)
NET INCREASE IN CASH AND CASH EQUIVALENTS

6,226,479

186,196

299,894
CASH AND CASH EQUIVALENTS, beginning of period

—

505,880

379,741
CASH AND CASH EQUIVALENTS, end of period

$
6,226,479

$
692,076

$
679,635
Supplemental cash flow information:

Cash paid for interest

$
276,246

$
34,505

$
280,010
Cash paid for taxes

$
—

$
5,355

$
17,468
Non-cash investing and financing activities:

Capital expenditures through issuance of common units

$
176,404,698

$
—

$
—


	Nine Months Ended September 30,
	2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(162,251,073)	$	(54,625,438)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and depletion expense		36,002,109		37,690,558
Impairment of oil and natural gas properties		158,698,835		65,828,980
Amortization of right-of-use assets		205,518		88,058
Amortization of loan origination costs		808,534		783,961
Equity (income) loss in affiliate		(460,360)		80,896
Forfeiture of restricted units		(118,859)		—
Unit-based compensation		7,088,114		5,692,926
Loss on commodity derivative instruments, net of settlements		4,496,376		878,255
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		3,131,377		5,270,397
Accounts receivable and other current assets		(870,069)		(389,839)
Accounts payable		(212,162)		(399,679)
Other current liabilities		1,611,232		3,198,198
Operating lease liabilities		(205,222)		(117,312)
Net cash provided by operating activities		47,924,350		63,979,961
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(50,737)		(829,724)
Purchase of oil and natural gas properties		(87,488,292)		(1,192,432)
Deposits on oil and natural gas properties		—		(986,000)
Investment in affiliate		(1,751,951)		(2,965,933)
Cash distribution from affiliate		457,410		—
Net cash used in investing activities		(88,833,570)		(5,974,089)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity offering		73,601,668		—
Contributions from Class B unitholders		—		470,000
Redemption of Class B contributions on converted units		(363,747)		(73,250)
Issuance costs paid on Series A preferred units		—		(717,612)
Redemption on Series A preferred units		(61,089,600)		—
Distributions to common unitholders		(22,113,488)		(25,506,173)
Distribution to OpCo unitholders		(16,559,322)		(25,650,921)
Distribution and accretion on Series A preferred units		(3,850,006)		(5,775,000)
Distribution on Class B units		(71,089)		(71,042)
Borrowings on long-term debt		157,065,176		3,951,933
Repayments on long-term debt		(87,500,000)		—
Payment of loan origination costs		(60,674)		(88,776)
Restricted units used for tax withholding		(6,259)		(21,036)
Net cash provided by (used in) financing activities		39,052,659		(53,481,877)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(1,856,561)		4,523,995
CASH AND CASH EQUIVALENTS, beginning of period		14,204,250		15,773,987
CASH AND CASH EQUIVALENTS, end of period	$	12,347,689	$	20,297,982
Supplemental cash flow information:
Cash paid for interest	$	3,928,101	$	3,572,952
Non-cash investing and financing activities:
Right-of-use assets obtained in exchange for operating lease liabilities	$	—	$	3,554,159
Units issued in exchange for oil and natural gas properties	$	28,140,093	$	171,550,000
Non-cash deemed distribution to Series A preferred units	$	2,382,614	$	4,633,752
Noncash effect of Series A preferred unit redemption	$	25,847,891	$	—
Redemption of Class B contributions on converted units in accounts payable	$	—	$	200,000

The accompanying notes are an integral part of these condensed consolidated financial statements.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Unless the context otherwise ~~requires,~~requires, references to “Kimbell Royalty Partners, LP,” ~~“the Partnership,~~the “Partnership,” ~~“we,” “our,” “us”~~ or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to ~~“the General~~the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. References to ~~“the Sponsors”~~“Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner. References to the “Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership. References to “the Predecessor,” or “Rivercrest” refer to Rivercrest Royalties, LLC, the predecessor for accounting and financial reporting purposes. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner.

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP is a Delaware limited partnership formed ~~on October 30, 2015. In connection with its formation, the Partnership issued a non-economic general partner interest~~ in ~~the Partnership~~2015 to ~~Kimbell Royalty GP, LLC, its general partner. The Partnership has adopted a fiscal year-end of December 31.~~

On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. Theown and acquire mineral and royalty interests ~~making up~~in oil and natural gas properties throughout the ~~Partnership’s initial assets were contributed to~~United States. Effective as of September 24, 2018, the Partnership by the Contributing Parties at the closing of the IPO. As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods ~~on or after February 8, 2017 refers~~has elected to ~~the Partnership~~be taxed as a ~~whole. The financial information presented~~corporation for ~~the periods on or~~ ~~prior to February 7, 2017, is solely that~~United States federal income tax purposes. As an owner of ~~the Predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. The~~ mineral and royalty interests, ~~underlying~~ the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGL”) ~~production revenues~~from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.properties in which it owns an interest.

The Predecessor is a Delaware limited liability company formed on October 25, 2013 to own oil, natural gas and NGL mineral and royalty interests in the United States of America (“United States”). In addition to mineral and royalty interests, the Predecessor’s assets include overriding royalty interests. These non-cost-bearing interests are collectively referred to as “mineral and royalty interests.” The Predecessor also had non-operated working interests in certain oil and natural gas properties. Prior to the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated asset retirement obligations (“ARO”) to an affiliated entity that was not contributed to the Partnership.

~~NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements ~~of the Partnership~~ have been prepared in accordance with accounting principles generally accepted ~~accounting principles~~ in the United States (“GAAP”) for interim financial information and with the instructions to Form ~~10‑Q~~10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange ~~Commission (“SEC”).~~Commission. As a result, the accompanying unaudited interim condensed consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim condensed consolidated financial statements and related notes should be read in conjunction with the Partnership’s ~~and the Predecessor’s financial statements for the years ended December 31, 2016 and 2015, which are included in the Partnership’s~~ Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2019, which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the ~~Partnership’s management,~~General Partner, the unaudited interim condensed consolidated financial statements contain all adjustments ~~of a normal recurring nature~~ necessary to fairly present the financial position and results of operations for the interim periods in accordance with ~~GAAP.~~GAAP and all adjustments are of a normal recurring nature. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.

~~Table~~Preparation of ~~Contents~~the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates.

~~KIMBELL ROYALTY PARTNERS, LP~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole.

~~Management Estimates~~COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

The ~~preparation~~global spread of coronavirus (“COVID-19”) created significant volatility, uncertainty, and economic disruption during the ~~unaudited consolidated financial statements~~first nine months of 2020. On March 11, 2020, the World Health Organization (the “WHO”) declared

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~~Other current liabilities consists~~KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Joint Ventures

The Partnership has partial ownership in a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed $15.0 million. The Joint Venture is managed by Springbok Operating Company, LLC. While certain members of ~~employee bonus accrual, ad valorem taxes and revenue processing fees.~~

~~Asset Retirement Obligations~~

~~Prior to the transactions that were completed in connection~~Springbok Operating Company, LLC are affiliated with the ~~closing~~entities acquired as part of the ~~Partnership’s IPO,~~Springbok Acquisition, none of the ~~Predecessor assigned its non-operated working~~assets held by the Joint Venture were included in the Springbok Acquisition. The purpose of the Joint Venture is to make direct or indirect investments in royalty, mineral and overriding royalty interests and associated ARO to an affiliated entity that was not contributed to the Partnership. The Predecessor’s ARO reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar ~~activities associated with the Predecessor’s non-operated working~~non-cost bearing interests in oil and gas properties, excluding leasehold or working interests. The Partnership currently utilizes the equity method of accounting for its investment in the Joint Venture. As of September 30, 2020, the Partnership had paid approximately $4.7 million under its capital commitment. In October 2020, the Partnership paid a capital contribution of $0.1 million, bringing the total amount paid under its capital commitment to approximately $4.8 million.

NOTE 4—DERIVATIVES

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural ~~gas properties.~~

~~Fair values of legal obligations to retire and remove long-lived assets were recorded when~~gas. To mitigate the ~~obligation was incurred. When~~inherent commodity price risk associated with its operations, the liability was initially recorded, the Predecessor capitalized this cost by increasing the carrying amount of the related property and equipment. Over time, the liability was accreted for the change in its present value and the capitalized cost inPartnership uses oil and natural gas ~~properties was depleted based on units~~commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty.

As of ~~production consistent with~~September 30, 2020, the ~~related asset.~~

~~Other Long-Term Liabilities~~

~~The Predecessor’s other long-term liabilities consist~~Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a ~~tenant improvement allowance granted at the effective date of the lease~~fixed price for the ~~Partnership’s office space. This allowance was accounted~~contract and pays a floating market price to the counterparty over a specified period for as a deferred incentive and was being amortized over the term of the lease as a reduction to rent expense. The deferred incentive was fully realized through the transactions that were completed in connection with the closing of the Partnership’s IPO and is not recognized in the Partnership’s financial statements.

~~Income Taxes~~

contracted volume. The Partnership is a master limited partnership and is taxed as a partnership under the Internal Revenue Code whereby the Partnership’s partners are taxed on their proportionate share of taxable income. The financial statements, therefore, do not include a provision for federal income taxes.

Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership and the Predecessor incurred de minimis amounts of state income taxes during 2017.

~~Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities,~~hedges its daily production based on the ~~technical merits~~amount of debt and/or preferred equity as a percent of its enterprise value. As of September 30, 2020, these economic hedges constituted approximately 33% of daily oil and natural gas production.

The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the ~~position. The Partnership~~contract period, and its natural gas fixed price swap transactions are settled based upon the ~~Predecessor had no uncertain tax positions at September 30, 2017~~last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and ~~December 31, 2016, respectively.~~

natural gas derivative contracts are settled in the production month.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Partnership and the Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to September 30, 2017, the Predecessor 2017 Period, and the nine months ended September 30, 2016, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions.

The Partnership has filed all tax returns to date that are currently due. Tax years after December 31, 2013 remain subject to possible examination by taxing authorities although no such examination has been requested.

~~Concentration of Credit Risk~~

The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGL produced and sold from its properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations.

At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not ~~experienced~~designated any ~~losses related to amounts in excess~~ of ~~federally insured limits.~~

~~Revenue Recognition~~

its derivative contracts as hedges for accounting purposes. The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii)records all derivative contracts at fair value. Changes in the ~~seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.~~

~~As an owner of mineral and royalty interests, the Partnership is entitled to a portion~~fair values of the revenues received from the production of oil, natural gas and associated NGLs from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and NGL sales from the properties is primarily determined by supply and demandPartnership’s derivative instruments are recognized as gains or losses in the ~~marketplace~~current period and ~~can fluctuate considerably. The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGL produced and sold from the properties.~~

~~To the extent actual volumes and prices of oil, natural gas and NGLs~~ are ~~unavailable for~~presented on a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within oil, natural gas and NGL receivablesnet basis in the accompanying unaudited condensed consolidated ~~balance sheets. Differences between estimates~~statements of ~~revenue~~operations. Changes in fair value consisted of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Beginning fair value of commodity derivative instruments	$	2,881,223	$	1,665,887	$	804,501	$	4,227,946
(Loss) gain on commodity derivative instruments		(5,897,646)		2,506,815		193,995		270,607
Net cash received on settlements of derivative instruments		(675,452)		(823,011)		(4,690,371)		(1,148,862)
Ending fair value of commodity derivative instruments	$	(3,691,875)	$	3,349,691	$	(3,691,875)	$	3,349,691

The following table presents the fair value of the Partnership’s derivative contracts as of September 30, 2020 and December 31, 2019:


		September 30,		December 31,
Classification	Balance Sheet Location	2020		2019
Assets:
Current asset	Commodity derivative assets	$	—	$	687,933
Long-term asset	Commodity derivative assets		—		116,568
Liabilities:
Current liability	Commodity derivative liabilities		(992,299)		—
Long-term liability	Commodity derivative liabilities		(2,699,576)		—
		$	(3,691,875)	$	804,501

As of September 30, 2020, the ~~actual amounts are adjusted and recorded in~~Partnership’s open commodity derivative contracts consisted of the ~~period that the actual amounts are known.~~following:

~~Fair Value Measurements~~Oil Price Swaps


	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High
September 2020 - December 2020	178,974	$	41.36	$	32.21	$	50.65
January 2021 - December 2021	535,455	$	44.26	$	34.95	$	56.10
January 2022 - September 2022	391,164	$	40.70	$	35.65	$	43.52

Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
October 2020 - December 2020	1,735,672	$	2.54	$	2.45	$	2.63
January 2021 - December 2021	6,886,090	$	2.54	$	2.33	$	2.85
January 2022 - September 2022	4,973,953	$	2.43	$	2.23	$	2.70

NOTE 5—FAIR VALUE MEASUREMENTS

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and ~~cash equivalents,~~NGL receivables, accounts receivable ~~accounts payable,~~ and other current assets and current and long-term liabilities ~~as reflected~~included in the ~~accompanying~~ unaudited condensed consolidated balance sheets ~~approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents~~approximated fair value as ~~the~~of September 30, 2020 and December 31, 2019 due to their short-term duration and variable interest rates that approximate ~~current market rates. These estimated fair values may not be representative~~prevailing interest rates as of ~~actual values of the~~each reporting period. As a result, these financial ~~instruments that could have been realized or that will be realized in the future.~~

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if

~~Table of Contents~~

~~KIMBELL ROYALTY PARTNERS, LP~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~observable inputs~~assets and liabilities are not ~~reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:~~discussed below.

●

Level 1— Unadjusted quoted market prices for identical assets or liabilities in active markets.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

●

Level 2—~~quoted market~~Quoted prices for similar assets or liabilities in ~~active markets; quoted prices for identical~~non-active markets, or ~~similar assets or liabilities in markets that are not active;~~ inputs ~~other than quoted prices~~ that are observable for the asset or liability, ~~and inputs derived principally from~~either directly or ~~corroborated by observable market data by correlation or other means.~~

~~Level 3—unobservable inputs~~indirectly, for substantially the full term of the asset or liability.

●

Level 3—Measurement based on prices or valuations models that require inputs that are both unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

~~The Predecessor’s ARO~~Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is ~~classified within Level 3 as~~significant to the fair value ~~is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as~~measurement. The Partnership’s assessment of the ~~existence~~significance of a ~~legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk-free rate~~particular input to ~~be used and inflation rates. See Note 8 for the summary of changes in~~ the fair value ofmeasurement in its entirety requires judgment and considers factors specific to the ~~Predecessor’s ARO for the Predecessor 2017 Period.~~

~~Recently Issued Accounting Pronouncements~~

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, “Business Combinations—Clarifying the Definition of a Business.” This update apples to all entities that must determine whether transactions should be accounted for as acquisitions (or disposals) of assetsasset or ~~businesses.~~liability. The ~~update requires that when substantially all of the~~Partnership recognizes transfers between fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the transaction should not be accounted for as a business. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years. This update should be and will be applied prospectively on or after the effective date. The adoption of this update will change the process that the Partnership uses to evaluate whether it has acquired a business or an asset. This update is not expected to have a material impact on the Partnership’s financial statements or results of operations.

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

In June 2016, the FASB issued ASU 2016‑13, “Measurement of Credit Losses on Financial Instruments.” ASU 2016‑13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earningshierarchy levels as of the ~~beginning~~end of the ~~first~~ reporting period in which the ~~guidance is adopted.~~event or change in circumstances causing the transfer occurred. The Partnership ~~does~~did not ~~believe this standard will~~ have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and nine months ended September 30, 2020 and 2019.

The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets.

The following tables summarize the Partnership’s assets and liabilities measured at fair value on a ~~material impact~~recurring basis by the fair value hierarchy:


	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total
September 30, 2020
Assets
Commodity derivative contracts	$	—	$	—	$	—	$	—	$	—
Liabilities
Commodity derivative contracts	$	—	$	(3,691,875)	$	—	$	—	$	(3,691,875)
December 31, 2019
Assets
Commodity derivative contracts	$	—	$	804,501	$	—	$	—	$	804,501
Liabilities
Commodity derivative contracts	$	—	$	—	$	—	$	—	$	—

NOTE 6—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:


	September 30,		December 31,
	2020		2019
Oil and natural gas properties
Proved properties	$	913,955,037	$	758,313,233
Unevaluated properties		235,028,364		275,041,784
Less: accumulated depreciation, depletion and impairment		(523,403,235)		(328,913,425)
Total oil and natural gas properties	$	625,580,166	$	704,441,592

Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made.

The Partnership assesses all unevaluated properties on ~~its financial statements.~~

~~In April 2016,~~a periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the ~~FASB issued ASU 2016-10, “Revenue from Contracts with Customers—Identifying Performance Obligations~~following factors, among others: economic and ~~Licensing.” This update clarifies two principles~~market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of Accounting Standards Codification (“ASC”) Topic 606, identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity.

proved

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

~~In March 2016,~~reserves; and the ~~FASB issued ASU 2016‑09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016‑09 simplifies several aspects~~economic viability of operator development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the ~~accounting for share-based payment transactions, including accounting for income taxes, forfeitures~~associated leasehold costs are transferred to the full cost pool and ~~statutory tax withholding requirements, as well as certain classification changes~~are then subject to amortization and to the full cost ceiling test. The Partnership transferred $48.6 million to the full cost pool in the ~~statement~~first quarter of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Partnership adopted this standard effective at the issuance of its restricted units under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) on May 12, 2017. The Partnership elected to account for forfeitures as they occur2020 as a result of ~~adopting~~ this ~~standard.~~

In March 2016, the FASB issued ASU 2016-08, “Revenue from Contracts with Customers—Principal versus Agent Considerations (Reporting Revenue Gross versus Net).” Under this update, an entity should recognize revenue to depict theimpairment assessment. The transfer ~~of promised goods or services to customers~~resulted in an additional ceiling test impairment expense for the nine months ended September 30, 2020 equal to the amount ~~that reflects~~of the ~~consideration~~transfer. There were no additional impairments to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, and early application is not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presentedunevaluated properties in the ~~financial statements,~~second or ~~modified retrospective adoption, meaning this update is applied only~~third quarters of 2020.

After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated proved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the ~~most current period presented.~~ Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties for the three months ended March 31, 2020. In addition, the Partnership does not intend to book PUD reserves going forward.

As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $22.2 million and $158.7 million during the three and nine months ended September 30, 2020, respectively. The impairment can primarily be attributed to the decline in the 12-month average price of oil and natural gas as a result of the continued impact of the external factors mentioned above.

The Partnership ~~is still evaluating~~recorded an impairment on its oil and natural gas properties of $34.9 million and $65.8 million during the ~~impact of this standard, however, it does not expect that there will be~~three and nine months ended September 30, 2019, respectively, primarily due to a ~~significant change~~decline in the ~~manner~~12-month average price of oil and natural gas.

NOTE 7—LEASES

Substantially all of the Partnership’s ~~revenue recognition.~~leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The ~~Partnership expects that certain additional disclosures will be required upon adoption of this standard. The Partnership is still determining which adoption method it will use.~~

~~In February 2016,~~Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the ~~FASB issued ASU 2016‑02, “Leases.” ASU 2016‑02 requires the recognition of~~lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying unaudited condensed consolidated balance sheets. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of September 30, 2020 is 8.60 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by ~~lessees~~the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for ~~those leases currently~~the operating lease was 6.75% for the nine months ended September 30, 2020.

Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2020 and 2019. The total operating lease expense recorded for the three and nine months ended September 30, 2020 was $0.1 million and $0.4 million, respectively.

Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases ~~and makes certain changes to~~are the ~~way~~main office spaces used for operations. In July 2019, the Partnership became the lessee in several other related lease ~~expenses are accounted for. This update is effective~~agreements for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. Theadditional office space. In addition, the Partnership ~~believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases.~~

In May 2014, the FASB issued ASU 2014-09, “Revenue From Contracts with Customers (Topic 606).” an ASU on a comprehensive new revenue recognition standard that will supersede ASC 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to includewas involved in the ~~transaction price, allocating the transaction price to each separate performance obligation,~~construction and ~~determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all~~design of the periods presented with a cumulative catch-up as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.

Based upon the substantial completion of review of our contracts and analysis done so far, the Partnership has not identified any revenue streams that would be materially impacted and does not expect the adoption of this standard to have a material effect on the Partnership’s financial statements. Our approach includes performing a detailed review of each of our revenue streams and comparing our historical accounting policies to the new standard. The Partnership will continue to monitor specific developments for our industry as it relates to ASU 2014-09. The Partnership anticipates using the modified retrospective method to adopt the new standard.

~~NOTE 3—ACQUISITIONS~~

~~In the second quarter of 2017, the Partnership acquired mineral and royalty interests~~ underlying 1.1 million gross acres (6,881 net royalty acres) for an aggregate purchase price of approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.

assets.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Future minimum lease commitments as of September 30, 2020 were as follows:


	Total		2020		2021		2022		2023		2024		Thereafter
Operating leases	$	4,271,715	$	122,003	$	480,025	$	478,837	$	480,579	$	486,323	$	2,223,948
Less: Imputed Interest		(1,078,012)
Total	$	3,193,703

NOTE 4—8—LONG-TERM DEBT

~~In connection with its IPO, the~~The Partnership ~~entered into~~maintains a ~~$50.0 million~~ secured revolving credit facility that is secured by substantially all of its assets, the Operating Company’s assets and the assets of ~~its~~their wholly owned subsidiaries. Availability under the secured revolving credit facility equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will be re-determined semi-annually on February 1 and August 1 of each year based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the its wholly owned subsidiaries. In connection with the August 1 redeterminationTotal commitments under the secured revolving credit facility are set at $225.0 million, and the borrowing base ~~was reaffirmed~~is set at ~~$100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0~~$300.0 million. The secured revolving credit facility permits aggregate commitments under the secured revolving credit facility to be increased to ~~$100.0~~up to $500.0 million, subject to the limitations of the Partnership’s borrowing base and the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The borrowing base will be redetermined semiannually on or about May 1 and November 1 of each year based on the value of the oil and natural gas properties of the Partnership, the Operating Company and their wholly owned subsidiaries. In connection with the May 1, 2020 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $300.0 million and total commitments will remain at $225.0 million. The borrowing base was reaffirmed in May, in part, because the assets acquired in the Springbok Acquisition provided support to the Partnership’s existing, pre-acquisition borrowing base. The November borrowing base redetermination is currently being conducted and is expected to be finalized by the end of November 2020. The secured revolving credit facility matures on February 8, 2022. The Partnership intends to request from its lenders an amendment to extend the term of the secured revolving credit facility beyond the current maturity date prior to March 31, 2021.

The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 4.0 to ~~1.0;~~1.0 and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facility also contains customary events of default, including ~~non‑payment,~~non-payment, breach of covenants, materially incorrect representations, ~~cross‑default,~~cross-default, bankruptcy and change of control.

During the three and nine months ended September 30, 2020, the Partnership borrowed an additional $0.5 million and $157.1 million under the secured revolving credit facility and repaid approximately $2.5 million and $87.5 million of the outstanding borrowings, respectively. As of September 30, ~~2017,~~2020, the Partnership’s outstanding balance was ~~$22.2~~$169.7 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of September 30, ~~2017.~~2020.

~~During the period ended~~As of September 30, ~~2017,~~2020, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of ~~2.25% and~~2.50% or Prime Rate (as defined in the secured revolving credit facility) plus a margin of ~~1.25%~~1.50%. For the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017,~~2020, the weighted average interest rate on the Partnership’s outstanding borrowings was ~~3.51%~~3.38%.

~~On January 31, 2014,~~NOTE 9—PREFERRED UNITS

In July 2018, the ~~Predecessor entered~~Partnership completed the private placement of 110,000 Series A preferred units to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $110.0 million. Until the conversion of the Series A preferred units into common

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the third anniversary of the original issuance date, and board appointment rights beginning the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units.

The Series A preferred units are convertible by the Series A Purchasers after two years at a ~~credit agreement with Frost Bank for up~~30% discount to ~~a $50.0 million revolving credit facility. The credit facility was~~the issue price, subject to ~~borrowing base restrictions~~certain conditions. The Partnership may redeem the Series A preferred units at any time. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and ~~was collateralized by certain properties. The borrowing base on~~(iii) the ~~Predecessor’s credit facility was $20.0 million with interest payable monthly on Alternate Base Rate loans or at the end~~Series A issue price plus accrued and unpaid distributions.

For purposes of the ~~interest period on~~Series A preferred units, “Minimum IRR” means as of any ~~Eurodollar loans, with all principal and unpaid interest due at maturity on January 15, 2018. As of December 31, 2016,~~measurement date: (a) prior to the Predecessor had outstanding advances on long-term debt totaling $10.6 million. On February 8, 2017, the Predecessor repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the salefifth anniversary of the ~~Predecessor’s mineral and royalty interests~~July 12, 2018 (the “Series A Issuance Date”), a 13.0% internal rate of return with respect to the ~~Partnership.~~

~~NOTE 5—COMMON UNITS~~Series A preferred units; (b) on or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary of the Series A Issuance Date, a 14.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the Series A Issuance Date, a 15.0% internal rate of return with respect to the Series A preferred units.

On February ~~8, 2017,~~12, 2020, the Partnership completed ~~its IPO~~the redemption of ~~5,750,000 common~~55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than 50% of the carrying value of the Series A preferred units as of the redemption date and 50% of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $5.7 million was taken directly to unitholders’ equity and non-controlling interest during the nine months ended September 30, 2020.

The following table summarizes the changes in the number of the Series A preferred units:


		Series A
		Preferred Units
Balance at December 31, 2019		110,000
Redemption of Series A preferred units		(55,000)
Balance at September 30, 2020		55,000

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner ~~interests, which included~~interests. As of September 30, 2020, the Partnership had a total of 38,948,023 common units issued and outstanding and 20,779,781 Class B units outstanding.

In January 2020, the Partnership completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 million (the “2020 Equity Offering”). The Partnership used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. In connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units ~~issued~~ pursuant to the exercise of the underwriters’ option to purchase additional common units. The ~~mineral and royalty interests making up~~Partnership did not receive any proceeds from the ~~initial assets were contributed to~~sale of the ~~Partnership~~common units by the ~~Contributing Parties at~~selling unitholders.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table summarizes the ~~time~~changes in the number of the ~~IPO. On May 12,~~Partnership’s common units:


		Common Units
Balance at December 31, 2019		23,518,652
Common units issued for equity offering		5,000,000
Common units issued for Springbok Acquisition		2,224,358
Conversion of Class B units		7,274,959
Common units issued under the LTIP (1)		946,638
Restricted units used for tax withholding		(1,018)
Forfeiture of restricted units		(15,566)
Balance at September 30, 2020		38,948,023

(1)	Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on February 28, 2020.

The following table presents information regarding the ~~Partnership issued 163,324 restricted units under the LTIP.~~

~~On May 2, 2017,~~common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) ~~declared a quarterly cash distribution of $0.23 per common unit~~ for the ~~period ended March 31, 2017.~~ periods presented:


	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2020	$	0.17	April 24, 2020	May 4, 2020	May 11, 2020
Q2 2020	$	0.13	July 24, 2020	August 3, 2020	August 10, 2020
Q3 2020	$	0.19	October 23, 2020	November 2, 2020	November 9, 2020

Q1 2019	$	0.37	April 26, 2019	May 6, 2019	May 13, 2019
Q2 2019	$	0.39	July 26, 2019	August 5, 2019	August 12, 2019
Q3 2019	$	0.42	October 25, 2019	November 4, 2019	November 11, 2019

The ~~distribution was paid on May 15, 2017 to unitholders of record as of~~following table summarizes the ~~close of business on May 8, 2017. The amount of~~changes in the ~~first quarter 2017 distribution was adjusted for the period from the date of the closing~~number of the Partnership’s ~~IPO through March 31, 2017.~~Class B units:


		Class B Units
Balance at December 31, 2019		25,557,606
Conversion of Class B units		(7,274,959)
Class B units issued for Springbok Acquisition		2,497,134
Balance at September 30, 2020		20,779,781

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~~KIMBELL ROYALTY PARTNERS, LP~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~On July 28, 2017,~~For each Class B unit issued, 5 cents has been paid to the ~~Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The distribution was paid on August 14, 2017 to unitholders of record~~Partnership as additional consideration (the “Class B Contribution”). Holders of the ~~close of business~~Class B units, are entitled to receive cash distributions equal to 2.0% per quarter on ~~August 7, 2017.~~

~~On August 9, 2017,~~their respective Class B Contribution, subsequent to distributions on the ~~Board of Directors, upon~~Series A preferred units but prior to distributions on the ~~advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of (i)~~ common units inand OpCo common units.

The Class B units and OpCo common units are exchangeable together into an ~~amount~~ equal ~~to $30,000 to certain non-employee directors~~number of the Partnership under the LTIP, which were fully vested as of the grant date, and (ii) a total of 4,247 restricted units to certain consultants under the LTIP. Such grants were made on August 11, 2017.

~~As of September 30, 2017, 16,509,799~~ common units of the ~~Partnership were outstanding.~~Partnership.

NOTE 6—11—EARNINGS (LOSS) PER ~~UNIT~~UNIT

Basic earnings (loss) per unit (“EPU”) is calculated by dividing net income (loss) attributable to common units 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~~restricted units granted under the Partnership’s LTIP for its employees, directors and consultants and unvested options granted under the Predecessor’s long-term incentive plan as described in Note 7—Unit-Based Compensation. For the Predecessor 2017 Period and the nine months ended September 30, 2016, the effectpotential conversion of the 110,000 options issued under the Predecessor’s long-term incentive plan were anti-dilutive. Therefore, the options issued under the Predecessor’s long-term incentive plan were not included in the diluted EPU calculation on the consolidated statementsClass B units.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or ~~liquidity.~~liquidity as of September 30, 2020.

NOTE ~~12—~~17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to September 30, ~~2017~~2020 in the preparation of its condensed consolidated financial statements.

Joint Venture

In October 2020, in connection with the Joint Venture, the Partnership paid capital contributions of $0.1 million.

Distributions

On November 4, 2020, the Partnership paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended September 30, 2020.

On November 4, 2020, the Partnership paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of $20,780 for the quarter ended September 30, 2020.

On October ~~27, 2017,~~23, 2020, the Board of Directors declared a quarterly cash distribution of ~~$0.31~~$0.19 per common unit for the quarter ended September 30, ~~2017.~~2020. The distribution will be paid on November ~~13, 2017~~9, 2020 to common unitholders and OpCo common unitholders of record as of the close of business on November ~~6, 2017.~~2, 2020.

On October 9, 2017, the Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility. The Partnership was required to pay a deposit, which is included in deposits on oil and natural gas properties in the accompanying unaudited consolidated balance sheet at September 30, 2017.

On November 8, 2017, the Partnership acquired mineral and royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price of approximately $7.3 million in various counties in Arkansas. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.

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

The following discussion and analysis of financial ~~condition~~condition and results of operations should be read together in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form ~~10‑Q~~10-Q (this “Quarterly Report”), as well as ~~the historical~~our audited financial statements ~~of our accounting predecessor for accounting~~ and ~~financial reporting purposes, Rivercrest Royalties, LLC, (“Rivercrest” or the “Predecessor”)~~notes thereto included in our Annual Report on Form ~~10‑K~~10-K for the year ended December 31, ~~2016.~~2019 (the “2019 Form 10-K”).

~~On February 8, 2017,~~Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” the “Partnership,” “we” or “us” refer to Kimbell Royalty Partners, LP ~~(the “Partnership,” “we” or “us”) completed~~and its ~~initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant~~subsidiaries. References to the ~~underwriters’ option~~“Operating Company” refer to ~~purchase additional common units. The~~Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. References to the “Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests comprising our initial assets were contributed to us by certain entities and individuals (the “Contributing Parties”), including certain affiliates of our founders (our “Sponsors”) at the time of our IPO. As a result, as of December 31, 2016, we had not yet acquired any of such assets.

~~Unless otherwise indicated in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the financial information presented~~ ~~for periods on or after February 8, 2017 refers~~ to the ~~Partnership as a whole. The financial information presented for periods on or prior to February 7, 2017 refers only to Rivercrest, the predecessor for accounting purposes,~~ and does not include the results of the Partnership as a whole. The interests underlying the oil, natural gas and natural gas liquids(“NGL”) production revenues of our Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.Partnership.

Cautionary Statement Regarding ~~Forward‑Looking~~Forward-Looking Statements

Certain statements and information in this Quarterly Report may constitute ~~forward‑looking~~forward-looking statements. ~~Forward‑looking~~Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify ~~forward‑looking~~forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no ~~forward‑looking~~forward-looking statements can be guaranteed. When considering these ~~forward‑looking~~forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any ~~forward‑looking~~forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such ~~forward‑looking~~forward-looking statements include:

●

our ability to replace our reserves;

●

our ability to make, consummate and integrate acquisitions of assets or businesses and realize the benefits or effects of any acquisitions or the timing, final purchase price or consummation of any acquisitions;

●

our ability to execute our business strategies;

●

the volatility of realized prices for oil, natural gas and natural gas ~~liquids;~~

liquids (“NGL”), including as a result of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”);

●

the level of production on our properties;

●

the level of drilling and completion activity by the operators of our properties;

●

regional supply and demand factors, delays or interruptions of production;

●

~~our ability to replace our reserves;~~

~~our ability to identify and complete acquisitions of assets or businesses;~~

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

political conditions, including the outcome of the U.S. presidential election and resulting energy and environmental policies, weakness in the capital markets or the ongoing and potential impact to financial markets and worldwide economic activity resulting from the ongoing coronavirus (“COVID-19”) pandemic and related governmental actions;

●

revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;

●

impacts of impairment expense on our financial statements;

●

competition in the oil and natural gas ~~industry;~~

industry generally and the mineral and royalty industry in particular;

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●

the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;

●

title defects in the properties in which we ~~invest;~~

acquire an interest;

●

uncertainties with respect to identified drilling locations and estimates of ~~reserves;~~

reserves on our properties and on properties we seek to acquire;

●

the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;

●

restrictions on or the availability of the use of water in the business of the operators of our properties;

●

the availability of transportation facilities;

●

the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

●

federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry;

●

future operating results;

●

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

●

operating hazards faced by the operators of our properties;

●

the ability of the operators of our properties to keep pace with technological advancements; ~~and~~

●

~~certain factors discussed elsewhere in this report.~~

uncertainties regarding United States federal income tax treatment of our future earnings and distributions; and

●

our ability to maintain effective internal controls over financial reporting and disclosure controls and procedures.

~~All forward‑looking~~These factors are discussed in further detail in our Annual Report on Form 10-K for the year ended December 31, 2019 under “Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, and in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2020 and June 30, 2020, under “Item 1A. Risk Factors” in Part II, and elsewhere in this report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are ~~expressly qualified in their entirety by the foregoing cautionary statements.~~made, whether as a result of new information, future events or otherwise.

Overview

~~Kimbell Royalty Partners, LP is~~We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, we have elected to be taxed as a corporation for United States ~~of America (“United States”).~~federal income tax purposes. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated ~~NGL~~NGLs from the acreage underlying our interests, net of ~~post‑production~~post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties ~~and third parties~~ and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of September 30, ~~2017,~~2020, we owned mineral and royalty interests in approximately ~~3.7~~9.0 million gross acres and overriding royalty interests in approximately ~~2.0~~4.6 million gross acres, with approximately ~~35%~~60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. We refer to these ~~non‑cost‑bearing~~non-cost-bearing interests collectively as our “mineral and royalty interests.” As of September 30, ~~2017,~~2020, over ~~95%~~98% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests,

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and substantially all of those leases were held by production. Our mineral and royalty interests are located in 2028 states and in ~~nearly~~ every major onshore basin across the continental United States and include ownership in over ~~50,000~~96,000 gross ~~producing~~ wells, including over ~~29,000~~40,000 wells in the Permian Basin.

The following table summarizes our ownership in United States basins and producing regions and information about the wells in which we have a mineral or royalty interest as of September 30, 2020:


			Average Daily	Average Daily
			Production	Production
Basin or Producing Region	Gross Acreage	Net Acreage	(Boe/d)(6:1)(1)	(Boe/d)(20:1)(2)	Well Count
Permian Basin	2,661,857	23,075	2,756	2,235	40,641
Mid‑Continent	3,953,268	41,464	1,729	1,042	11,159
Haynesville	786,423	7,665	3,284	1,124	8,771
Appalachia	741,293	23,202	1,936	791	3,159
Bakken	1,569,637	6,051	671	587	3,985
Eagle Ford	624,135	6,730	1,706	1,374	3,058
Rockies	73,912	1,036	755	420	12,350
Other	3,232,561	36,695	1,323	751	13,016
Total	13,643,086	145,918	14,160	8,324	96,139

(1)

“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read “Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves” in our Annual Report on Form 10-K for the year ended December 31, 2019.

(2)	“Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business.

The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of September 30, 2020:


Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	235	201	0.75	0.61
Mid‑Continent	109	70	0.23	0.07
Haynesville	61	19	0.37	0.07
Appalachia	53	44	0.24	0.14
Bakken	150	158	0.12	0.32
Eagle Ford	98	49	0.53	0.34
Rockies	88	32	0.38	0.29
Total	794	573	2.62	1.84

(1)	The above table represents drilled but uncompleted wells and permitted locations only, and there is no guarantee that the drilled but uncompleted wells or permitted locations will be developed into producing wells in the future.

Recent Developments

Joint Venture

In October 2020, in connection with the joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, we paid capital contributions of $0.1 million.

Third Quarter Distributions

On November 4, 2020, we paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended September 30, 2020.

Each holder of Class B units has paid five cents per Class B unit to us as an additional capital contribution for the Class B units (such aggregate amount, the “Class B Contribution”) in exchange for Class B units. Each holder of Class B

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units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution. On November 4, 2020, we paid a quarterly cash distribution to each Class B unitholder, resulting in a total quarterly distribution of $20,780 for the quarter ended September 30, 2020.

On October 23, 2020, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.19 per common unit for the quarter ended September 30, 2020. The distribution will be paid on November 9, 2020 to common unitholders and OpCo common unitholders of record as of the close of business on November 2, 2020.

Business Environment

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption during the first nine months of 2020. On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, our oil, natural gas, and NGL operators and other parties with whom we have business relations, including a significant reduction in the global demand for oil and natural gas. This significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance has led to a significantly weaker outlook for oil and gas producers and is having a disruptive impact on the oil and natural gas industry. Globally, these conditions have led to significant economic contraction.

Our first priority in our response to this crisis has been the health and safety of our employees, the employees of our business counterparties and the community in which we operate. To address these concerns, we have modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the WHO and other governmental and regulatory authorities. In mid-March, we restricted access to our offices to only essential employees, and directed the remainder of our employees to work from home to the extent possible. Beginning in mid-May we opened our offices to employees on a voluntary basis, with employees having the option to work from our office or from home. These restrictions have had minimal impact on our operations to date and have allowed us to maintain the engagement and connectivity of our personnel, as well as minimize the number of employees in the office.

There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. While shelter-in-place restrictions subsided in the third quarter of 2020, the possibility of future restrictions remains as certain jurisdictions have begun re-opening only to face increases in new COVID-19 cases. One of the largest impacts of the pandemic has been a significant reduction in global demand for oil and, to a lesser extent, natural gas. This significant decline in demand has been met with a sharp decline in oil prices which has been exacerbated by the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries. Although OPEC finalized an agreement in April 2020 to cut oil production by 9.7 million barrels per day during May and June 2020, and agreed in June 2020 to extend such production cuts until the end of July 2020, crude oil prices have remained depressed as a result of an increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other related industries. These industry conditions, coupled with those resulting from the COVID-19 pandemic, have led to significant global economic contraction generally and in our industry in particular.

Oil and natural gas prices have historically been volatile; however, the volatility in the prices for these commodities has substantially increased as a result of COVID-19, the OPEC announcements mentioned above and ongoing storage capacity concerns. Oil prices declined sharply in April 2020 and have remained low. Although strip pricing for natural gas has increased meaningfully, the impact of these recent developments on our business and the oil

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~~Recent Developments~~and gas industry is unpredictable. Although we derived approximately 33% of our revenues and 59% of our production on a Boe/d basis (6:1) from natural gas for the third quarter of 2020, which we believe presents some downside protection against depressed oil prices, we expect that low oil prices and commodity price volatility will continue through the fourth quarter of 2020 and perhaps longer.

In April 2020, we received notices from two operators regarding well shut-ins and curtailments of production on properties in which we own an interest. The properties were primarily located in the Eagle Ford Shale, and the production attributable to such properties on a Boe/d basis (6:1) represented approximately one percent of our total production for the first quarter of 2020. We received subsequent notice that the curtailment on all Eagle Ford Shale production has ceased and production resumed, effective June 1, 2020. We also received notifications of well shut-ins and curtailment in the second quarter of ~~2017,~~2020 from additional operators and the ~~Partnership acquired mineral~~production attributable to such properties on a Boe/d basis (6:1) accounted for less than one percent of our total production for the second quarter of 2020. We did not receive any notification of shut-ins or curtailment in the third quarter of 2020. We expect that as the supply and ~~royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres, for~~demand imbalance resulting from the COVID-19 outbreak and the OPEC announcements mentioned above continues, and as oil storage facilities reach capacity and/or purchasers of crude products cancel previous orders, more of our operators may adjust or reduce their drilling activities, which could have an ~~aggregate purchase price~~adverse effect on our business, cash flows, liquidity, financial condition and results of ~~approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its revolving credit facility.~~

~~On October 9, 2017,~~operations in the ~~Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for~~fourth quarter of 2020. Due to the expected significant decline in the average of the trailing twelve month first-of-month pricing used in the full-cost ceiling test, we expect to record an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility. The Partnership was requiredimpairment to ~~put down a deposit which is included in deposits on~~our oil and natural gas properties in the ~~accompanying unaudited consolidated balance sheet at September 30, 2017.~~fourth quarter of 2020 as a result of the full-cost ceiling limitation.

~~On November 8, 2017,~~The ultimate impacts of COVID-19 and the ~~Partnership acquired mineral~~volatility currently being experienced in the oil and ~~royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price~~natural gas markets on our business, cash flows, liquidity, financial condition and results of ~~approximately $7.3 million~~operations will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development and availability of effective treatments and vaccines, the duration of the outbreak, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other thirds parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in ~~various counties in Arkansas. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.~~this report.

~~Business Environment~~

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. ~~In late 2014, prices for~~As noted above, the supply and demand imbalance resulting from the COVID-19 outbreak and various OPEC announcements have created increased volatility in oil and natural gas ~~declined precipitously, and prices remained low throughout 2015 and~~prices. The table below demonstrates such volatility for the ~~majority of 2016 until rebounding in~~periods presented as reported by the ~~fourth quarter of 2016. During the nine months ended September 30, 2017, West Texas Intermediate~~United States Energy Information Administration (“~~WTI”~~EIA”) ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $54.48 per Bbl on February 23, 2017, and during the nine months ended September 30, 2016, WTI ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $51.23 per Bbl on June 8, 2016. During the nine months ended September 30, 2017, the Henry Hub spot market price of natural gas ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017. During the nine months ended September 30, 2016, the Henry Hub spot market price of natural gas ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $3.19 per MMBtu on September 21, 2016. .


	Nine Months Ended September 30, 2020				Nine Months Ended September 30, 2019
	High		Low		High		Low
Oil ($/Bbl)	$	63.27	$	(36.98)	$	66.24	$	46.31
Natural gas ($/MMBtu)	$	2.57	$	1.33	$	4.25	$	2.02

On October 30, ~~2017,~~2020, the ~~WTI~~West Texas Intermediate posted price for crude oil was ~~$54.11~~$35.64 per Bbl and the Henry Hub spot market price of natural gas was ~~$2.94~~$3.03 per MMBtu.

The following table, as reported by the ~~U.S. Energy Information Administration (“EIA”),~~EIA, sets forth the average daily prices for oil and natural ~~gas for~~gas.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Oil ($/Bbl)	$	40.89	$	56.34	$	38.04	$	56.75
Natural gas ($/MMBtu)	$	2.00	$	2.38	$	1.87	$	2.62

Rig Count

Drilling on our acreage is dependent upon the ~~three~~exploration and ~~nine months ended September 30, 2017~~production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and ~~2016:~~future leasing and drilling activity on our acreage.

For the three months ended September 30,

For the nine months ended September 30,
EIA Average Price:

2017

2016

2017

2016
Oil (Bbl)

$
48.18

$
44.85

$
49.30

$
41.35
Natural gas (MMBtu)

$
2.95

$
2.88

$
3.01

$
2.34

~~Source: EIA~~

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The Baker Hughes ~~U.S.~~United States Rotary Rig count ~~was 940~~decreased by 69.1% from 860 active rigs atas of September ~~29, 2017, an 80% increase from 522~~30, 2019 to 266 active rigs atas of September 30, ~~2016. In addition, according~~2020.

According to the Baker Hughes ~~U.S.~~United States Rotary Rig count, rig activity in the 2028 states in which we own mineral and royalty interests ~~increased 83% from 468~~included 263 active rigs atas of September 30, ~~2016~~2020 compared to ~~857~~851 active rigs atas of September ~~29, 2017.~~30, 2019. The ~~active~~decrease in rig count ~~across~~is directly related to the COVID-19 outbreak and international supply and demand imbalances. See Business Environment — COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas for further discussion.

The following table summarizes the number of active rigs operating on our acreage ~~at October 31, 2017 totaled 21 rigs, a 40% increase compared to~~by United States basins and producing regions for the ~~15 rigs at year-end 2016.~~periods indicated:


	September 30,
Basin or Producing Region	2020	2019
Permian Basin	12	31
Mid‑Continent	5	13
Haynesville	8	15
Appalachia	1	2
Bakken	2	12
Eagle Ford	1	4
Rockies	1	5
Total	30	82

Sources of Our Revenue

Our ~~revenues and our Predecessor’s~~ revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. For the three months ended September 30, 2017, our revenues were generated 57% from oil sales, 30% from natural gas sales, 11% from NGL sales and 2% from other sales. For the three months ended September 30, 2016, our Predecessor’s revenues were generated 60% from oil sales, 30% from natural gas sales and 10% from NGL sales. For

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the period from February 8, 2017 to September 30, 2017, our revenues were generated 59% from oil sales, 29% from natural gas sales, 11% from NGL sales and 1% from other sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined nine months ended September 30, 2017, the revenues were generated 58% from oil sales, 30% from natural gas sales, 11% from NGL sales and 1% from other sales. For the nine months ended September 30, 2016, our Predecessor’s revenues were generated 61% from oil sales, 29% from natural gas sales and 10% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

~~Neither we nor~~The following table presents the breakdown of our ~~Predecessor~~operating income for the following periods:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Royalty income
Oil sales	57	%	54	%	57	%	53	%
Natural gas sales	33	%	36	%	34	%	36	%
NGL sales	10	%	7	%	9	%	9	%
Lease bonus and other income	-	%	3	%	-	%	2	%
	100	%	100	%	100	%	100	%

We entered into ~~hedging arrangements~~oil and natural gas commodity derivative agreements with Frost Bank, beginning January 1, 2018 which extend through September 2022, to establish, in advance, a price for the sale of a portion of the oil, natural gas and NGLs produced from our mineral and royalty interests. ~~As a result, we may realize the benefit~~

Table of ~~any short‑term increase in the price of oil, natural gas~~Contents

Non-GAAP Financial Measures

Adjusted EBITDA and ~~NGLs, but we will not be protected against decreases in price, and if the price of oil, natural gas and NGLs decreases significantly, our business, results of operation~~Cash Available for Distribution

Adjusted EBITDA and cash available for distribution ~~may be materially adversely effected. We may enter into hedging arrangements in the future.~~

~~Adjusted EBITDA~~

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

We define Adjusted EBITDA as net income (loss) ~~plus interest expense,~~, net of ~~capitalized interest, non‑cash unit‑based~~non-cash unit-based compensation, change in fair value of open commodity derivative instruments, transaction costs, impairment of oil and natural gas properties, income taxes, interest expense and depreciation ~~depletion~~ and ~~accretion~~depletion expense. Adjusted EBITDA is not a measure of ~~the~~net income (loss) as determined by ~~the~~ generally accepted accounting principles in the United States (“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. We define cash available for distribution as Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

Adjusted EBITDA and cash available for distribution should not be considered an alternative to net income (loss), oil, natural gas and NGL revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA and cash available for distribution may not be comparable to other similarly titled measures of other companies.

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The tables below present a reconciliation of Adjusted EBITDA to net ~~income (loss)~~loss and net cash provided by operating activities, ~~the~~our most directly comparable GAAP financial measures, for the periods indicated (unaudited).


	Partnership		Predecessor		Partnership		Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,		Nine Months Ended September 30,
	2017		2016		2017		2017		2016
Net income (loss)	$	119,029	$	(769,166)	$	653,898	$	(496,856)	$	(6,018,014)
Depreciation, depletion and accretion expense		4,488,915		418,969		11,156,292		113,639		1,244,023

											Three Months Ended September 30,				Nine Months Ended September 30,
											2020		2019		2020		2019
Reconciliation of net loss to Adjusted EBITDA:
Net loss											$	(25,676,624)	$	(28,914,588)	$	(162,251,073)	$	(54,625,438)
Depreciation and depletion expense												10,704,945		15,098,107		36,002,109		37,690,558
Interest expense		225,302		103,596		468,429		39,307		314,081		1,603,006		1,468,419		4,689,907		4,332,633
State income taxes		—		4,212		—		—		13,401
(Benefit from) provision for income taxes												(694,864)		102,997		(694,864)		610,798
EBITDA		4,833,246		(242,389)		12,278,619		(343,910)		(4,446,509)		(14,063,537)		(12,245,065)		(122,253,921)		(11,991,449)
Impairment of oil and natural gas properties		—		306,959		—		—		4,992,897		22,237,131		34,880,071		158,698,835		65,828,980
Unit‑based compensation		434,197		151,265		569,889		50,422		453,795		2,446,329		1,809,752		7,088,114		5,692,926
Adjusted EBITDA	$	5,267,443	$	215,835	$	12,848,508	$	(293,488)	$	1,000,183
Loss (gain) on commodity derivative instruments, net of settlements												6,573,098		(1,683,804)		4,496,376		878,255
Cash distribution from affiliate												210,999		—		457,410		—
Equity income in affiliate												(292,803)		—		(460,360)		—
Consolidated Adjusted EBITDA												17,111,217		22,760,954		48,026,454		60,408,712
Adjusted EBITDA attributable to noncontrolling interest												(5,953,129)		(11,348,462)		(17,700,368)		(31,696,443)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP												11,158,088		11,412,492		30,326,086		28,712,269
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		166,707		219,900		276,246		34,505		280,010		902,448		611,885		2,474,715		1,819,003
Capital expenditures		—		—		—		—		—
Cash available for distribution	$	5,100,736	$	(4,065)	$	12,572,262	$	(327,993)	$	720,173
Cash distributions on Series A preferred units												627,639		965,208		2,419,992		2,712,948
Cash income tax expense												—		147,000		—		651,000
Distributions on Class B units												23,141		23,414		71,089		71,042
Cash reserves												—		(147,000)		—		(651,000)
Cash available for distribution on common units											$	9,604,860	$	9,811,985	$	25,360,290	$	24,109,276

Partnership

Predecessor

Partnership

Predecessor

Three Months Ended September 30,

Three Months Ended September 30,

Period from February 8, 2017 to September 30,

Period from January 1, 2017 to February 7,

Nine Months Ended September 30,

2017

2016

2017

2017

2016
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

Net cash provided by operating activities

$
5,387,438

$
406,518

$
13,965,478

$
186,719

$
956,793
Interest expense

225,302

103,596

468,429

39,307

314,081
State income taxes

—

4,212

—

—

13,401
Impairment of oil and natural gas properties

—

(306,959)

—

—

(4,992,897)
Amortization of loan origination costs

(15,625)

(12,723)

(41,667)

(4,241)

(34,245)
Amortization of tenant improvement allowance

—

(32,603)

—

2,864

25,777
Unit-based compensation

(434,197)

(151,265)

(569,889)

(50,422)

(453,795)
Changes in operating assets and liabilities:

Oil, natural gas and NGL revenues receivable

555,908

1,258,156

496,886

(14,551)

(11,258)
Other receivables

65,175

(1,246,269)

258,785

(333,056)

(1,246,269)
Accounts payable

228,080

(274,023)

(152,569)

(247,972)

1,071,453
Other current liabilities

(1,178,835)

8,971

(2,146,834)

77,442

(89,550)
EBITDA

$
4,833,246

$
(242,389)

$
12,278,619

$
(343,910)

$
(4,446,509)
Add:

Impairment of oil and natural gas properties

—

306,959

—

—

4,992,897
Unit‑based compensation

434,197

151,265

569,889

50,422

453,795
Adjusted EBITDA

$
5,267,443

$
215,835

$
12,848,508

$
(293,488)

$
1,000,183

2026

Table of Contents


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	12,379,324	$	24,835,447	$	47,924,350	$	63,979,961
Interest expense		1,603,006		1,468,419		4,689,907		4,332,633
(Benefit from) provision for income taxes		(694,864)		102,997		(694,864)		610,798
Impairment of oil and natural gas properties		(22,237,131)		(34,880,071)		(158,698,835)		(65,828,980)
Amortization of right-of-use assets		(69,559)		(65,480)		(205,518)		(88,058)
Amortization of loan origination costs		(275,898)		(265,812)		(808,534)		(783,961)
Equity income (loss) in affiliate		292,803		(80,896)		460,360		(80,896)
Forfeiture of restricted units		12,614				118,859		—
Unit-based compensation		(2,446,329)		(1,809,752)		(7,088,114)		(5,692,926)
(Loss) gain on commodity derivative instruments, net of settlements		(6,573,098)		1,683,804		(4,496,376)		(878,255)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		4,272,714		(1,937,752)		(3,131,377)		(5,270,397)
Accounts receivable and other current assets		559,160		64,269		870,069		389,839
Accounts payable		194,641		10,991		212,162		399,679
Other current liabilities		(1,150,481)		(1,461,535)		(1,611,232)		(3,198,198)
Operating lease liabilities		69,561		90,306		205,222		117,312
EBITDA		(14,063,537)		(12,245,065)		(122,253,921)		(11,991,449)
Add:
Impairment of oil and natural gas properties		22,237,131		34,880,071		158,698,835		65,828,980
Unit-based compensation		2,446,329		1,809,752		7,088,114		5,692,926
Loss (gain) on commodity derivative instruments, net of settlements		6,573,098		(1,683,804)		4,496,376		878,255
Cash distribution from affiliate		210,999		—		457,410		—
Equity income in affiliate		(292,803)		—		(460,360)		—
Consolidated Adjusted EBITDA		17,111,217		22,760,954		48,026,454		60,408,712
Adjusted EBITDA attributable to noncontrolling interest		(5,953,129)		(11,348,462)		(17,700,368)		(31,696,443)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP	$	11,158,088	$	11,412,492	$	30,326,086	$	28,712,269

Factors Affecting the Comparability of Our Results to ~~the~~Our Historical Results ~~of Our Predecessor~~

Our ~~Predecessor’s~~ historical financial condition and results of operations may not be comparable, either from period to period or going forward, to ~~the Partnership’s~~our future financial condition and results of operations, for the reasons described below.

~~No Effect Given to Transactions in Connection with Initial Public Offering~~Ongoing Acquisition Activities

~~The historical financial statements~~Acquisitions are an important part of our ~~Predecessor included in this Quarterly Report do not reflect the financial condition or results~~growth strategy, and we expect to pursue acquisitions of operations of the Partnership. Further, these historical financial statements do not give effect to the transactions that were completed in connection with the closing of the Partnership’s IPO. In connection with our IPO, our Predecessor assigned all of its non‑operating working interests to an affiliate that was not contributed to us, and all of the membership interests of our Predecessor were contributed to us in exchange for common units and a portion of the net proceeds from the IPO. In addition, the Contributing Parties directly or indirectly contributed to us the other assets that made up our initial assets in exchange for common units and a portion of the net proceeds from the IPO. The combination of the assets contributed to us by the Contributing Parties was accounted for at fair value as an asset acquisition. The fair value of the purchase price consideration was based upon the value of the common units purchased in the Partnership’s IPO by third-party investors.

The historical financial data of our Predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the Partnership as a whole and may not provide an accurate indication of what our actual results would have been if the transactions completed in connection with our IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The mineral and royalty interests from third parties, affiliates of our ~~Predecessor only represent approximately 11%~~Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our ~~total~~Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three and nine months ended September 30, 2020 and 2019 include the acquisition of all of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC that own oil and natural gas mineral and royalty interests (the “Phillips Acquisition”), the acquisition of certain mineral and royalty assets from certain affiliates of Buckhorn Resources GP, LLC (the “Buckhorn Acquisition”) and the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”).

Table of Contents

Further, the affiliates of our Sponsors and Contributing Parties have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such parties offer them to us. We may decide to fund any acquisition, including any potential dropdowns, with cash, common units, other equity securities, proceeds from borrowings under our secured revolving credit facility or the issuance of debt securities, or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.

We typically do not announce a transaction until after we have executed a definitive agreement. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future ~~undiscounted cash flows, based on~~acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the ~~reserve report prepared by Ryder Scott as~~acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of ~~December 31, 2016.~~any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.

Impairment of Oil and Natural Gas Properties

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.

NoAfter evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries and other supply factors, we determined that significant drilling uncertainty existed regarding our proved undeveloped (“PUD”) reserves that were included in our total estimated proved reserves as of December 31, 2019, as well as our unevaluated oil and natural gas properties. Specifically, with respect to our PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), we determined that we did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment ~~expense was recorded~~on such properties for the ~~period from February 8, 2017 to September 30, 2017. The substantial majority~~three months ended March 31, 2020. We similarly recorded an impairment on the value of our ~~proved~~unevaluated oil and natural gas properties ~~that were acquired at~~for the time of the IPO were recorded at fair value as of the IPO. In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the U.S. Securities and Exchange Commission (“SEC”) to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the periodthree months ended March 31, ~~2017 and will remain effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that we are required~~2020, which primarily were acquired in various acquisitions since our initial public offering. There were no additional impairments to ~~assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets~~unevaluated properties in the ~~full-cost ceiling test would not be appropriate.~~ second or third quarters of 2020.

As of September 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, we considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closingresult of our ~~IPO~~

~~Table of Contents~~

~~was based~~full cost ceiling analysis, we recorded an impairment on ~~forward strip~~our oil and natural gas ~~pricing existing at the date~~properties of ~~the IPO~~$22.2 million and management affirmed that there has not been a material change to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at September 30, 2017 of $240.8 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $78.4$158.7 million for the nine months ending September 30, 2017. We will continue to assess the fair value of the acquired assets at each periodic reporting date to ensure inclusion in the ceiling calculation is not required through the December 31, 2017 reporting period, which is the period of the exemption extended by the SEC. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired.

~~During~~during the three and nine months ended September 30, ~~2016, our Predecessor recorded non-cash~~2020, respectively. The impairment ~~charges of approximately $0.3 million and $5.0 million, respectively,~~can primarily ~~due~~be attributed to ~~changes in reserve values resulting from~~ the decline in ~~commodity prices and other factors. We may incur impairment charges in~~ the ~~future, which could materially adversely affect our results of operations for the periods in which such charges are taken.~~

~~Credit Agreements~~

In connection with our IPO, we entered into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. As of September 30, 2017, we had borrowed $22.2 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC (“Kimbell Operating”) and the acquisition of mineral and royalty interests for an aggregate purchase12-month average price of ~~approximately $20.7 million. For~~oil and natural gas as a result of the ~~three months ended September 30, 2017~~continued impact of the external factors mentioned above.

We recorded an impairment on our oil and ~~the period from February 8, 2017 to September 30, 2017, we incurred $225,302~~natural gas properties of $34.9 million and ~~$468,429, respectively, in interest expense.~~

~~In January 2014, our Predecessor entered into a credit agreement with Frost Bank, as lender. For the Predecessor 2017 Period and~~$65.8 million during the three and nine months ended September 30, ~~2016,~~2019, respectively, primarily due to a decline in the 12-month average price of oil and natural gas.

As discussed in our ~~Predecessor’s interest expense was $39,307, $103,596 and $314,081, respectively. Our Predecessor had outstanding borrowings of $10.6 million as of~~Annual Report on Form 10-K for the year ended December 31, ~~2016. We did~~2019, we do not ~~assume any indebtedness~~intend to book proved undeveloped reserves going forward. As such, additional impairment charges could be recorded in connection

Table of ~~our Predecessor~~Contents

with future acquisitions. Further, due to the expected significant decline in ~~connection with~~ the ~~IPO.~~

~~Acquisition Opportunities~~

~~Acquisitions are an important part~~average of ~~our growth strategy, and~~the trailing twelve month first-of-month pricing used in the full-cost ceiling test, we expect to ~~pursue acquisitions of mineral~~record an impairment to our oil and royalty interests from our Sponsors, the Contributing Parties and third parties. We also may pursue acquisitions jointly with our Sponsors and the Contributing Parties. As a consequence of any such acquisition and acquisition‑related expense, the historical financial statements of our Predecessor will differ from our financial statementsnatural gas properties in the ~~future.~~

~~Management Services Agreements~~

~~In connection with our IPO, we entered into~~fourth quarter of 2020 as a management services agreement with Kimbell Operating, which entered into separate service agreements with certain entities controlled by affiliates of our Sponsors and Benny D. Duncan, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective services agreements, affiliates of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution to our unitholders.

~~Non‑Operated Working Interest Assignment~~

Prior to the transactions that were completed in connection with the IPO, our Predecessor assigned its non‑operated working interests and associated asset retirement obligations to an affiliated entity that was not contributed to the Partnership. Asresult of the ~~closing~~full-cost ceiling limitation. If the expected significant decline in the price of ~~its IPO~~oil, natural gas and NGLs continues through ~~the date of this Quarterly Report, the Partnership does not own any working interests and does not have any asset retirement obligations~~future periods or ~~any lease operating expenses~~if prices decrease further in future periods, we may be required to record additional impairments as a ~~working interest owner.~~result of the full-cost ceiling limitation.

~~Table of Contents~~

Results of Operations

The table below summarizes our ~~and our Predecessor’s~~ revenue and expenses and production data for the periods indicated (unaudited).


	Partnership		Predecessor		Partnership		Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,		Nine Months Ended September 30,
	2017		2016		2017		2017		2016

											Three Months Ended September 30,				Nine Months Ended September 30,
											2020		2019		2020		2019
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	8,351,399	$	969,084	$	20,656,741	$	318,310	$	2,572,477	$	24,325,893	$	29,531,138	$	66,686,729	$	80,278,506
Lease bonus and other income												15,916		940,898		313,844		2,313,548
(Loss) gain on commodity derivative instruments, net												(5,897,646)		2,506,815		193,995		270,607
Total revenues												18,444,163		32,978,851		67,194,568		82,862,661
Costs and expenses
Production and ad valorem taxes		778,733		120,315		1,602,520		19,651		203,567		1,840,607		2,236,405		4,916,858		5,757,742
Depreciation, depletion and accretion expense		4,488,915		418,969		11,156,292		113,639		1,244,023
Depreciation and depletion expense												10,704,945		15,098,107		36,002,109		37,690,558
Impairment of oil and natural gas properties		—		306,959		—		—		4,992,897		22,237,131		34,880,071		158,698,835		65,828,980
Marketing and other deductions		424,702		320,698		1,068,509		110,534		570,521		2,511,919		2,332,010		6,692,850		5,938,093
General and administrative expenses		2,314,718		463,501		5,707,093		532,035		1,252,001		6,110,846		5,694,534		19,500,306		17,248,399
Total costs and expenses		8,007,068		1,630,442		19,534,414		775,859		8,263,009		43,405,448		60,241,127		225,810,958		132,463,772
Operating income (loss)		344,331		(661,358)		1,122,327		(457,549)		(5,690,532)
Operating loss												(24,961,285)		(27,262,276)		(158,616,390)		(49,601,111)
Other income (expense)
Equity income (loss) in affiliate												292,803		(80,896)		460,360	��	(80,896)
Interest expense		225,302		103,596		468,429		39,307		314,081		(1,603,006)		(1,468,419)		(4,689,907)		(4,332,633)
Income (loss) before income taxes		119,029		(764,954)		653,898		(496,856)		(6,004,613)
State income taxes		—		4,212		—		—		13,401
Net income (loss)	$	119,029	$	(769,166)	$	653,898	$	(496,856)	$	(6,018,014)
Other expense												(100,000)		—		(100,000)		—
Net loss before income taxes												(26,371,488)		(28,811,591)		(162,945,937)		(54,014,640)
(Benefit from) provision for income taxes												(694,864)		102,997		(694,864)		610,798
Net loss												(25,676,624)		(28,914,588)		(162,251,073)		(54,625,438)
Distribution and accretion on Series A preferred units												(1,577,968)		(3,469,584)		(6,232,620)		(10,408,752)
Net loss attributable to noncontrolling interests												9,482,090		16,146,535		63,429,454		33,398,555
Distribution on Class B units												(23,141)		(23,414)		(71,089)		(71,042)
Net loss attributable to common units											$	(17,795,643)	$	(16,261,051)	$	(105,125,328)	$	(31,706,677)
Production Data:
Oil (Bbls)		108,692		13,752		267,966		3,696		41,548		362,363		298,907		1,060,957		794,471
Natural gas (Mcf)		888,694		93,794		2,205,292		32,961		343,078		4,601,729		5,412,002		13,283,208		12,778,885
Natural gas liquids (Bbls)		46,493		4,850		108,929		1,220		17,458		173,392		164,202		504,066		418,106
Combined volumes (Boe) (6:1)		303,301		34,234		744,444		10,410		116,186		1,302,710		1,365,109		3,778,891		3,342,391

Comparison of the Three Months Ended September 30, ~~2017~~2020 to the Three Months Ended September 30, ~~2016~~2019

The period presented for the three months ended September 30, 2017 and 2016 includes the results of operations of the Partnership and our Predecessor, respectively. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

Oil, Natural Gas and ~~Natural Gas Liquids~~NGL Revenues

For the three months ended September 30, ~~2017,~~2020, our oil, natural gas and NGL revenues were ~~$8.4~~$24.3 million, ~~an increase~~a decrease of ~~$7.4~~$5.2 million from ~~$1.0~~$29.5 million for the three months ended September 30, ~~2016.~~2019. The significant decrease in oil, natural gas and NGL revenues was directly related to the decrease in the average prices we received for oil, natural gas and NGL production for the three months ended September 30, 2020 as discussed below. This decrease was partially offset by an increase in ~~revenues was~~revenue primarily ~~due to~~associated with the ~~$247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.~~

~~Table of Contents~~

Springbok Acquisition.

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30, 2020, a decrease of 62,399 Boe or 678 Boe/d, from 1,365,109 Boe or 14,838 Boe/d, for the three months ended September 30, ~~2017, an increase of 269,067 Boe or 2,925 Boe/d, from 34,234 Boe or 372 Boe/d,~~2019. The decrease in production for the three months ended September 30, ~~2016. The~~2020 was partially offset by an increase in production ~~realized from~~primarily associated with the ~~overriding royalty interests we acquired from Maxus Energy Corporation in late April 2017 enabled us to offset natural~~Springbok Acquisition, which accounted for 204,380 Boe or 2,222 Boe/d. Our production ~~declines from our existing portfolio and to exit~~for the ~~quarter~~three months ended September 30, ~~2017~~2019 included a non-routine increase in production related to the recognition of unknown upside production associated with ~~slightly higher production.~~the assets acquired in our 2018 acquisition of certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (the “Haymaker Acquisition”), which accounted for 188,882 Boe or 2,053 Boe/d.

Our operators received an average of ~~$43.95~~$38.36 per Bbl of oil, ~~$2.79~~$1.76 per Mcf of natural gas and ~~$19.75~~$13.42 per Bbl of NGL for the volumes sold during the three months ended September 30, ~~2017. Our Predecessor’s operators received an average of $42.08~~2020 compared to $54.87 per Bbl of oil, ~~$3.11~~$2.05 per Mcf of natural gas and ~~$20.37~~$12.52 per Bbl of NGL for the volumes sold during the three months ended September 30, ~~2016.~~2019. The three months ended September 30, ~~2017 increased 4.4%~~2020 decreased 30.1% or ~~$1.87~~$16.51 per Bbl of oil and ~~decreased 10.3%~~14.1% or ~~$0.32~~$0.29 per Mcf of natural gas as compared to the three months ended September 30, ~~2016. The increase in the average price received for oil~~2019. This change is consistent with ~~increase in the price of oil~~prices experienced in the market, specifically when compared to the EIA average price ~~increase~~decreases of ~~7.4%~~27.4% or ~~$3.33~~$15.45 per Bbl of ~~oil.~~oil and 16.0% or $0.38 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income was $0.02 million for the three months ended September 30, 2020, a decrease of $0.88 million from $0.9 million for the three months ended September 30, 2019. The ~~change~~significant decrease in lease bonus and other income is ultimately a result of the current volatility and uncertainty in the ~~average~~oil and gas market, which has discouraged operators from drilling new wells.

(Loss) Gain on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended September 30, 2020 included $6.6 million of mark-to-market losses and $0.7 million of gains on the settlement of commodity derivative instruments compared to $1.7 million of mark-to-market gains and $0.8 million of gains on the settlement of commodity derivative instruments for the three months ended September 30, 2019. We recorded a mark-to-market loss for the three months ended September 30, 2020 as a result of the increase in strip pricing from the three months ended June 30, 2020 to the three months ended September 30, 2020. The mark-to-market gain recorded for the three months ended September 30, 2019 was due to the decrease in the price ~~received for~~of oil and natural gas ~~was attributable~~contracts relative to the ~~diversification of~~fixed-price in our ~~natural gas producing interests when compared to the natural gas producing interests of our Predecessor.~~open derivative contracts.

Production and Ad Valorem Taxes

~~Our production~~Production and ad valorem taxes for the three months ended September 30, ~~2017~~2020 were ~~$0.8~~$1.8 million, ~~an increase~~a decrease of ~~$0.7~~$0.4 million from ~~$0.1~~$2.2 million infor the three months ended September 30, ~~2016.~~2019. The ~~increase~~decrease in production and ad valorem taxes was ~~attributable~~primarily related to the ~~$247.8 million acquisition of various mineral~~significant decrease in the average prices we received for oil, natural gas and ~~royalty interests from~~NGL production for the ~~Contributing Parties at the closing of our IPO~~three months ended September 30, 2020.

Depreciation and ~~the relevant production and revenues from those acquired interests.~~Depletion Expense

Depreciation ~~Depletion~~ and ~~Accretion Expense~~

~~Our depreciation,~~ depletion ~~and accretion~~ expense for the three months ended September 30, ~~2017 was $4.5~~2020 were $10.7 million, ~~an increase~~a decrease of ~~$4.1~~$4.4 million ~~from our Predecessor’s depreciation, depletion and accretion expense of $0.4~~from$15.1 million for the three months ended September 30, 2016. The increase in the depreciation, depletion and accretion expense was primarily attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired properties.2019.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a ~~units‑of‑production~~units-of-production basis. Estimates of proved developed ~~producing~~ reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was ~~$14.66~~$8.16 for the three months ended September 30, ~~2017, an increase~~2020, a decrease of ~~$4.87~~$2.87 per barrel from ~~$9.79~~the $11.03 average depletion rate per barrel for the three months ended September 30, ~~2016.~~2019. The ~~increase~~decrease in the ~~average~~ depletion rate ~~per barrel~~ was ~~primarily attributable~~due to the ~~$247.8 million acquisition of various mineral and royalty interests from~~significant impairment that was recorded during the ~~Contributing Parties at the closing of our IPO~~year ended December 31, 2019 and the ~~relevant production from those acquired~~six months ended June 30, 2020, which significantly reduced our net capitalized oil and natural gas properties.

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Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

NoWe recorded an impairment expense on our oil and natural gas properties of $22.2 million and $34.9 million during the three months ended September 30, 2020 and 2019, respectively. The impairment recorded during the three months ended September 30, 2020 was due to the recent significant decline in the trailing twelve month average of oil and natural gas prices, related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors. The impairment recorded for the three months ended September 30, ~~2017. See “Factors Affecting~~2019 was primarily a result of a decline in the ~~Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment~~12-month average price of oil and natural gas properties for the Partnership in the current period. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired.gas.

~~Impairments for our Predecessor totaled $0.3 million for the three months ended September 30, 2016 primarily due to the impact that declines in commodity prices had on the value of reserve estimates.~~

Marketing and Other Deductions

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increase of ~~$0.1~~$0.2 million from ~~our Predecessor’s marketing and other deductions~~$2.3 million for the three months ended September 30, ~~2016 of $0.3 million. The increase in marketing and other deductions~~2019, which was attributable to the ~~$247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.~~Springbok Acquisition.

General and Administrative Expenses

~~Our general~~General and administrative expenses for the three months ended September 30, ~~2017~~2020 were ~~$2.3~~$6.1 million, an increase of ~~$1.8~~$0.4 million from ~~our Predecessor’s general and administrative expenses of $0.5~~$5.7 million for the three months ended September 30, ~~2016.~~2019. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to ~~the increased cost related to operating the Partnership as~~ a ~~publicly traded company.~~$0.6 million increase in unit-based compensation expense, which was partially offset by a $0.2 million decrease in cash general and administrative expenses.

Interest Expense

Interest ~~Expense~~

~~Our interest~~ expense for the three months ended September 30, ~~2017~~2020 was ~~$0.2~~$1.6 million as compared to ~~our Predecessor’s interest expense of $0.1~~$1.5 million for the three months ended September 30, ~~2016.~~2019. The increase in interest expense was primarily due to debt incurred to fund the Springbok Acquisition. The increase in interest expense was partially offset by the repayment of $2.5 million in debt during the three months ended September 30, 2020 and the decline in the weighted average interest rate from 4.57% during the three months ended September 30, 2019 to 2.92% during the three months ended September 30, 2020.

Comparison of the Nine Months Ended September 30, ~~2017~~2020 to the Nine Months Ended September 30, ~~2016~~2019

~~The period presented for~~Oil, Natural Gas and NGL Revenues

For the nine months ended September 30, ~~2017 includes the results of operations of~~2020, our ~~Predecessor for the Predecessor 2017 Period~~oil, natural gas and our results of operations for the period from February 8, 2017 to September 30, 2017. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

~~Oil, Natural Gas and Natural Gas Liquids Revenues~~

~~For the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period, our and our Predecessor’s~~NGL revenues were ~~$20.7 and $0.3~~$66.7 million, ~~respectively, for combined revenues~~a decrease of ~~$21.0~~$13.6 million from $80.3 million for the nine months ended September 30, ~~2017, an increase of $18.4 million, from $2.6 million~~2019. The significant decrease in oil, natural gas and NGL revenues was directly related to the decrease in the average prices we received for oil, natural gas and NGL production for the nine months ended September 30, ~~2016. The~~2020 as discussed below. This decrease was partially offset by an increase in ~~revenues was primarily due to~~production associated with various acquisitions throughout the ~~$247.8 million acquisition of various mineral~~2019 and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.~~2020 periods.

Our ~~and our Predecessor’s~~ revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were ~~744,444~~3,778,891 Boe or ~~3,168 Boe/d and 10,410 Boe or 274~~13,792 Boe/d, for the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017 and~~2020, an increase of 436,500 Boe or 1,549 Boe/d, from 3,342,391 Boe or 12,243 Boe/d, for the ~~Predecessor 2017 Period, respectively.~~nine months ended September 30, 2019. The ~~combined~~increase in production for the nine months ended September 30, ~~2017~~2020 was ~~754,854~~primarily attributable to production associated with the Springbok Acquisition, which accounted for 375,535 Boe or ~~2,765~~2,249 Boe/~~d, an increase of 638,668 Boe or 2,341 Boe/d, from 116,186 Boe or 424 Boe/d,~~d. Our production for the nine months ended September 30, ~~2016. The~~2019 included a non-routine increase in production ~~realized from~~related to the ~~overriding royalty interests we~~recognition of unknown upside production associated with the assets acquired ~~from Maxus Energy Corporation~~ in ~~late April 2017 enabled us to offset natural production declines from our existing portfolio and to exit~~ the ~~quarter ended September 30, 2017 with slightly higher production.~~Haymaker Acquisition, which accounted for 188,882 Boe or 2,053 Boe/d.

Our operators received an average of ~~$45.14~~$36.08 per Bbl of oil, ~~$2.77~~$1.70 per Mcf of natural gas and $20.85 per Bbl of NGL for the volumes sold during the period from February 8, 2017 to September 30, 2017. Our Predecessor’s operators received an average of $47.04 per Bbl of oil, $3.47 per Mcf of natural gas and $24.61 per Bbl of NGL for the volumes sold during the Predecessor 2017 Period. For the combined nine months ended September 30, 2017, the operators received an average of $45.16 per Bbl of oil, $2.78 per Mcf of natural gas and $20.90 per Bbl of NGL for the volumes sold. Our Predecessor’s operators received an average of $38.11 per Bbl of oil, $2.14 per Mcf of natural gas and $14.56$11.47 per Bbl of NGL for the volumes sold during the nine months ended September 30, ~~2016. Average prices received by~~2020 compared to $54.65 per Bbl of oil, $2.33 per Mcf of natural gas and $16.83 per Bbl of NGL for the ~~operators~~volumes sold during the ~~combined~~ nine months ended September 30, ~~2017 increased 18.5%~~2019.

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The nine months ended September 30, 2020 decreased 34.0% or ~~$7.05~~$18.57 per Bbl of oil and ~~29.9%~~27.0% or ~~$0.64~~$0.63 per Mcf of natural gas as compared to the nine months ended September 30, ~~2016. These increases are~~2019. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price ~~increases~~decreases of ~~19.2%~~33.0% or ~~$7.95~~$18.71 per Bbl of oil and 28.6% or ~~$0.67~~$0.75 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

~~Table~~Lease bonus and other income was $0.3 million for the nine months ended September 30, 2020, a decrease of ~~Contents~~

$2.0 million from $2.3 million for the nine months ended September 30, 2019. The significant decrease in lease bonus and other income is ultimately a result of the current volatility and uncertainty in the oil and gas market, which has discouraged operators from drilling new wells.

(Loss) Gain on Commodity Derivative Instruments

Gain on commodity derivative instruments for the nine months ended September 30, 2020 included $4.5 million of mark-to-market losses and $4.7 million of gains on the settlement of commodity derivative instruments compared to $0.9 million of mark-to-market losses and $1.1 million of gains on the settlement of commodity derivative instruments for the nine months ended September 30, 2019. We recorded a mark-to-market loss for the nine months ended September 30, 2020 as a result of the increase in volumes hedged due to the Springbok Acquisition, offset by the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts. We recorded a mark-to-market loss for the nine months ended September 30, 2019 as a result of the increase in volumes hedged due to the Haymaker Acquisition, partially offset by the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts.

Production and Ad Valorem Taxes

Our production and ad valorem taxes for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $1.6 million and $0.02 million, respectively. The combined productionProduction and ad valorem taxes for the nine months ended September 30, ~~2017~~2020 were ~~$1.6~~$4.9 million, ~~an increase~~a decrease of ~~$1.4~~$0.9 million from $0.2 million in the nine months ended September 30, 2016. The increase in production and ad valorem taxes was attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.

~~Depreciation, Depletion and Accretion Expense~~

Our and our Predecessor’s depreciation, depletion and accretion expense for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period was $11.2 million and $0.1 million respectively for a combined expense of $11.3$5.8 million for the nine months ended September 30, ~~2017. This~~2019. The decrease in production and ad valorem taxes was ~~an increase~~primarily related to the significant decrease in the average prices we received for oil, natural gas and NGL production for the nine months ended September 30, 2020.

Depreciation and Depletion Expense

Depreciation and depletion expense for the nine months ended September 30, 2020 was $36.0 million, a decrease of ~~$10.1~~$1.7 million from ~~our Predecessor’s depreciation, depletion and accretion expense of $1.2~~$37.7 million for the nine months ended September 30, ~~2016.~~2019. The ~~increase~~decrease in the depreciation ~~depletion~~ and ~~accretion~~depletion expense was ~~primarily attributable to~~partially offset by the ~~$247.8 million~~ acquisition of various mineral and royalty interests ~~from~~in Oklahoma, the ~~Contributing Parties at the closing of our IPO~~Buckhorn Acquisition, and the ~~relevant production from those acquired properties.~~Springbok Acquisition which together added approximately $160.9 million of depletable costs to the full-cost pool.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a ~~units‑of‑production~~units-of-production basis. Estimates of proved developed ~~producing~~ reserves are a major component in the calculation of depletion. Our ~~and our Predecessor’s~~ average depletion rate per barrel was ~~$14.84 and $10.31~~$9.47 for the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017 and~~2020, a decrease of $1.79 per barrel from the ~~Predecessor 2017 Period, respectively. The combined~~$11.26 average depletion rate per barrel for the nine months ended September 30, ~~2017 was $14.78, an increase of $4.07 per barrel from an average~~2019. The decrease in the depletion rate ~~of $10.71 per barrel for~~was due to the ~~nine~~significant impairment that was recorded during the year ended December 31, 2019 and the six months ended ~~September~~June 30, ~~2016. The increase in the average depletion rate per barrel was primarily attributable to the $247.8 million acquisition~~2020, which significantly reduced our net capitalized oil and natural gas properties.

Table of ~~various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired properties.~~Contents

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

NoWe recorded an impairment expense ~~was recorded for~~on our oil and natural gas properties of $158.7 million and $65.8 million during the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017. See “Factors~~2020 and 2019, respectively. The impairment recorded during the nine months ended September 30, 2020 included an impairment due to the reduction in our PUD reserves, impairment of our unevaluated oil and natural gas properties in the first quarter of 2020 and impairments on our oil and natural gas properties as the result of the continued decline in the 12-month average price of oil and natural gas, in each case as further described under “—Factors Affecting the Comparability of Our Results to ~~the~~Our Historical ~~Results of Our Predecessor―~~Results—Impairment of Oil and Natural Gas ~~Properties” for a discussion regarding the exemption of~~Properties.”

The impairment of oil and natural gas properties for the Partnership for the period from February 8, 2017 to September 30, 2017. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired.

~~Impairments for our Predecessor totaled $5.0 million~~recorded for the nine months ended September 30, ~~2016~~2019 was primarily ~~due to~~a result of a decline in the ~~impact that declines in commodity prices had on the value~~12-month average price of ~~reserve estimates.~~oil and natural gas.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a ~~post‑production expense, and our Predecessor’s marketing and other deductions also include lease operating expenses related to its non‑operated working interests.~~post-production expense. Marketing ~~and other deductions for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $1.1 million and $0.1 million, respectively. The combined marketing~~ and other deductions for the nine months ended September 30, ~~2017~~2020 were ~~$1.2~~$6.7 million, an increase of ~~$0.6~~$0.8 million from ~~our Predecessor’s marketing and other deductions~~$5.9 million for the nine months ended September 30, ~~2016 of $0.6 million.~~2019. The increase in marketing and other deductions was primarily attributable to the ~~$247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.~~Springbok Acquisition.

General and Administrative Expenses

~~Our and our Predecessor’s general~~General and administrative expenses for the ~~period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $5.7 million and $0.5 million, respectively. General and administrative~~

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~~expenses for the combined~~ nine months ended September 30, ~~2017~~2020 were ~~$6.2~~$19.5 million, an increase of ~~$4.9~~$2.3 million from ~~our Predecessor’s general and administrative expenses of $1.3~~$17.2 million for the nine months ended September 30, ~~2016.~~2019. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to ~~the increased costs related to operating the Partnership as~~ a ~~publicly traded company.~~

~~Interest Expense~~

~~Our~~$1.4 million increase in unit-based compensation expense and cash general and administrative expenses resulting from increases in salaries and wages and our ~~Predecessor’s interest~~costs associated with company growth.

Interest Expense

Interest expense for the ~~period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period was $0.5 million and $0.04 million, respectively. The interest expense for the combined~~ nine months ended September 30, ~~2017~~2020 was ~~$0.5~~$4.7 million as compared to ~~our Predecessor’s interest expense of $0.3~~$4.3 million for the nine months ended September 30, ~~2016.~~2019. The increase in interest expense was primarily due to debt incurred to fund the partial redemption of the Series A preferred units and the Springbok Acquisition, which was partially offset by the repayment of $87.5 million in debt during the nine months ended September 30, 2020 and the decline in the weighted average interest rate from 4.68% during the nine months ended September 30, 2019 to 3.38% during the nine months ended September 30, 2020.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations and equity and debt financings and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. ~~We have entered into a $50.0 million~~Total commitments under our secured revolving credit facility ~~with an accordion feature permitting~~are set at $225.0 million and the borrowing base is set at $300.0 million. The secured revolving credit facility permits aggregate commitments under the secured revolving credit facility to be increased to up to ~~$100.0~~$500.0 million, ~~(subject~~subject to the limitations of our borrowing base and the satisfaction of certain conditions and the procurement of additional commitments from new or existing ~~lenders),~~lenders, to ~~initially~~ be used for general partnership purposes, including working capital and acquisitions, and certain IPO-related transaction expenses. In connection with the August 1 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million, providing for maximum availability under the secured revolving credit facility of $50.0 million.among other things. As of ~~November 8, 2017,~~October 30, 2020, we had an outstanding balance of ~~$29.6~~$169.8 million under our secured revolving credit facility.

~~Our~~Cash Distribution Policy

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement

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requires us to distribute all of our cash on hand at the end of each quarter ~~less reserves established by~~in an amount equal to our ~~general partner. We refer to this~~available cash ~~as “available cash.”~~for such quarter. Available cash for each quarter will be determined by the ~~General Partner’s~~ Board of Directors ~~(the “Board of Directors”)~~ following the end of such quarter. “Available cash,” as used in this context, is defined in the limited liability company agreement of the Operating Company and our partnership agreement. We expect that the Operating Company’s available cash for each quarter will generally equal ~~or approximate our~~its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs ~~including replacement~~that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations and fixed charges, tax obligations and reserves for future operating or ~~growth~~ capital ~~expenditures,~~needs that the Board of Directors may determine is appropriate.

~~Unlike a number~~In light of ~~other master limited partnerships, we do not generally intend~~the unprecedented global economic impact resulting from the COVID-19 pandemic, the related impact to ~~retain cash from our operations for capital expenditures necessary to replace our existing~~the United States oil and natural gas ~~reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that~~markets and the ~~continued development~~potential for further curtailments of production, during its determination of “available cash” for the third quarter of 2020, the Board of Directors approved the allocation of 25% of our ~~properties and completion~~cash available for distribution for the third quarter of ~~drilled but uncompleted wells by working interest owners will substantially offset~~2020 for the ~~natural production declines from~~repayment of $3.7 million in outstanding borrowings under our ~~existing wells. If they believe it is warranted,~~secured revolving credit facility. With respect to future quarters, the Board of Directors may ~~withhold replacement capital expenditures from~~continue to allocate cash ~~available for distribution,~~generated by our business to the repayment of outstanding borrowings under our secured revolving credit facility or in other manners in which ~~would reduce~~ the ~~amount~~Board of Directors determines to be appropriate at the time, and the Board of Directors may further change its policy with respect to cash distributions in the future.

We do not currently maintain a material reserve of cash ~~available~~ for the purpose of maintaining stability or growth in our quarterly distribution, innor do we intend to incur debt to pay quarterly distributions, although the period(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amountBoard of ~~cash generated from our existing properties will decrease and we~~Directors may ~~have to reduce the amount of distributions payable to our unitholders.~~change this policy.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt ~~securities, although~~securities. For example, we financed the Phillips Acquisition with equity consideration of 9,400,000 OpCo common units and an equal number of Class B units, the Buckhorn Acquisition with equity consideration of 2,169,348 OpCo common units and an equal number of Class B units, and the Springbok Acquisition with a combination of cash consideration funded with borrowings of approximately $95.0 million under our secured revolving credit facility and equity consideration of 2,224,358 common units and 2,497,134 OpCo common units and an equal number of Class B units. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, or(ii) otherwise reserve cash for distributions or to(iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

~~Because our partnership agreement requires us~~On November 4, 2020, we paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended September 30, 2020.

On November 4, 2020, we paid a quarterly cash distribution to ~~distribute an amount~~each Class B unitholder equal to ~~all available cash we generate each~~2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of $20,780 for the quarter our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the priceended September 30, 2020.

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of oil, natural gas and natural gas liquids, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of our quarterly distributions may be significant and could result in our not making any distribution for any particular quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The Board of Directors may change our distribution policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters.

On ~~May 2, 2017,~~October 23, 2020, the Board of Directors declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The Partnership’s calculated cash available for distribution was $0.18 per common unit for the quarter. However, during the period ended March 31, 2017, pursuant to the contribution agreement entered into by the Contributing Parties prior to the IPO, the Partnership received cash from the Contributing Parties for oil, natural gas and NGL production for periods prior to the IPO. The Board of Directors voted to distribute an additional $0.05 per common unit. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

On July 28, 2017, the Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The Partnership’s calculated cash available for distribution was $0.28 per common unit for the quarter. The Board of Directors voted to distribute an additional $0.02 per common unit due to excess working capital generated primarily from positive prior period production from our operators. The distribution was paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017.

~~On October 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.31~~$0.19 per common unit for the quarter ended September 30, ~~2017.~~2020. The distribution will be paid on November ~~13, 2017~~9, 2020 to common unitholders and OpCo common unitholders of record as of the close of business on November ~~6, 2017.~~2, 2020.

Cash Flows

The table below presents our cash flows ~~and our Predecessor’s cash flows~~ for the periods ~~indicated (in thousands).~~indicated.

Partnership

Predecessor

Period from February 8, 2017 to September 30,

Period from January 1, 2017 to February 7,

Nine Months Ended September 30,

2017

2017

2016

Cash Flow Data:

Cash flows provided by operating activities

$
13,965

$
187

$
957

Cash flows used in investing activities

(117,190)

(1)

(94)

Cash flows provided by (used in) financing activities

109,451

—

(563)

Net increase in cash

$
6,226

$
186

$
300


	Nine Months Ended September 30,
	2020		2019
Cash Flow Data:
Net cash provided by operating activities	$	47,924,350	$	63,979,961
Net cash used in investing activities		(88,833,570)		(5,974,089)
Net cash provided by (used in) financing activities		39,052,659		(53,481,877)
Net (decrease) increase in cash and cash equivalents	$	(1,856,561)	$	4,523,995

Operating Activities

Our ~~and our Predecessor’s~~ operating cash flow is impacted by many variables, the most significant of which ~~is the change~~are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and ~~NGL.~~NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our ~~and our Predecessor’s~~ control and are difficult to predict. Cash flows provided by operating activities for the ~~period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $14.0 million and $0.2 million, respectively. Cash flows provided by operating activities for the combined~~ nine months ended September 30, ~~2017~~2020 were ~~$14.2~~$47.9 million, ~~an increase~~a decrease of ~~$13.2~~$16.1 million compared to ~~our Predecessor’s cash flows provided by operating activities of $1.0~~$64.0 million for the nine months ended September 30, ~~2016.~~2019. The ~~increase~~decrease in cash flows provided by operating activities was ~~largely~~primarily attributable to the ~~$247.8 million acquisition of various mineral~~decrease in the average prices we received for oil, natural gas and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant~~NGL production ~~and revenues from those acquired interests.~~

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~~Investing Activities~~

~~Cash flows used in investing activities~~ for the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017 were $117.2 million, an increase of $117.1 million compared to our Predecessor’s cash~~2020.

Investing Activities

Cash flows used in investing activities for the nine months ended September 30, ~~2016 of $0.1 million. Our Predecessor’s cash flows used in investing activities were de minimis for~~2020 increased by $82.9 million compared to the ~~Predecessor 2017 Period.~~nine months ended September 30, 2019. For the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017,~~2020, we used $87.5 million primarily to fund the ~~$96.2~~Springbok Acquisition and $1.8 million to fund the capital commitments of the Joint Venture, partially offset by a $0.5 million cash distribution received in ~~proceeds received from our IPO to pay~~connection with the ~~cash portion of our acquisition of oil and natural gas properties at~~Joint Venture during the ~~IPO and~~period. For the nine months ended September 30, 2019, we used ~~$20.7~~$3.0 million to fund the capital commitments of the Joint Venture, $1.2 million to fund the Phillips Acquisition, $1.0 million to fund the deposit in connection with the acquisition of various mineral and royalty ~~interests.~~interests in Oklahoma and $0.8 million to fund the remodel of our office space.

Financing Activities

Cash flows provided by financing activities ~~was $109.5 million for the period from February 8, 2017 to September 30, 2017 as compared to our Predecessor’s cash used in financing activities of $0.6~~were $39.1 million for the nine months ended September 30, ~~2016. Our Predecessor did not have any~~2020 compared to $53.5 million in cash flows used in orfinancing activities for the nine months ended September 30, 2019. Cash flows provided by financing activities for the ~~Predecessor 2017 Period. During the period from February 8, 2017 to~~nine months ended September 30, ~~2017, we received $96.2~~2020 consists of $157.1 million of additional borrowings under our secured revolving credit facility and $73.6 million in proceeds from the 2020 Equity Offering. Cash flows provided by financing activities for the nine months ended September 30, 2020 were partially offset by $87.5 million used to repay borrowings under our ~~IPO, we borrowed $22.2~~secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units, $42.6 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units and $0.4 million paid ~~a distribution~~in connection with the redemption of Class B units. Cash flows used in financing activities for the nine months ended September 30, 2019 primarily consists of $57.0 million of distributions paid to ~~unitholders~~holders of ~~$8.7~~common units and OpCo common units, Series A Preferred Units and Class B Units and $0.7 million of issuance costs paid on Series A Preferred Units, partially offset by $4.0 million of additional borrowings under our secured revolving credit facility and ~~paid loan origination costs~~$0.5 million in contributions from our Class B unitholders.

Table of ~~$0.3 million.~~ Contents

Capital Expenditures

During the nine months ended September 30, ~~2016, our Predecessor repaid $0.6~~2020, we paid approximately $87.5 million ~~on its long‑term debt.~~

~~Capital Expenditures~~

primarily in connection with the Springbok Acquisition. During the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017,~~2019, we ~~acquired mineral and royalty interests from the Contributing Parties for common units with a total value at the IPO of $169.1 million and $96.2~~paid approximately $1.2 million in ~~cash. Additionally, we spent an aggregate amount of $20.7~~connection with the Phillips Acquisition and a $1.0 million ~~for~~deposit in connection with the acquisition of various mineral and royalty ~~interests. During the Predecessor 2017 Period, our Predecessor spent $523 on additional lease and well equipment and intangible drilling costs related to the Predecessor’s working~~ interests and office equipment. During the nine months ended September 30, 2016, our Predecessor spent $0.1 million on additional lease and well equipment and intangible drilling costs related to the Predecessor’s working interests and office equipment.in Oklahoma.

Indebtedness

~~Revolving Credit Agreement~~

We ~~entered into~~maintain a ~~$50.0 million~~secured revolving credit facility ~~in connection with our IPO, which~~that is secured by substantially all of our assets, the Operating Company’s assets and the assets of our and the Operating Company’s wholly owned subsidiaries. ~~Under the~~Availability under our secured revolving credit facility ~~availability under the facility will equal~~equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base. ~~The~~Total commitments under our secured revolving credit facility are set at $225.0 million and the borrowing base will be re-determined semi-annually on February 1 and August 1 of each year based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries.is set at $300.0 million. The secured revolving credit facility permits aggregate commitments under ~~the~~our secured revolving credit facility to be increased to ~~$100.0~~up to $500.0 million, subject to the limitations of our borrowing base and the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The borrowing base will be redetermined semiannually on or about May 1 and November 1 of each year based on the value of our and the Operating Company’s oil and natural gas properties and the oil and natural gas properties of our and the Operating Company’s wholly owned subsidiaries. In connection with the ~~August~~May 1, 2020 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at ~~$100.0~~$300.0 million and total commitments remained at $225.0 million. ~~Aggregate~~The borrowing base was reaffirmed in May, in part, because the assets acquired in the Springbok Acquisition provided support to our existing, pre-acquisition borrowing base. The November borrowing base redetermination is currently being conducted and is expected to be finalized by the end of November 2020. In connection with any future redetermination, it is possible that the borrowing base will be reduced as a result of a decrease in the value of the assets underlying the borrowing base in connection with a sustained decrease in oil and natural gas prices. Even in the event that our borrowing base is reduced and assuming that the aggregate maximum commitments ~~remain at $50.0 million providing for maximum availability~~of the lenders under the secured revolving credit facility do not change, until such reduction or series of ~~$50.0 million.~~reductions in the aggregate is greater than $75.0 million, our ability to borrow would not be impacted because until that point the borrowing base would exceed the current commitments under the secured revolving credit facility. The secured revolving credit facility matures on February 8, 2022. We intend to request from our lenders an amendment to extend the term of the secured revolving credit facility beyond the current maturity date prior to March 31, 2021.

The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facility also contains customary events of default, including ~~non‑payment,~~non-payment, breach of covenants, materially incorrect representations, ~~cross‑default,~~cross-default, bankruptcy and change of control. As of ~~November 8, 2017,~~September 30, 2020, we ~~have borrowed $29.6~~had outstanding borrowings of $169.7 million ~~to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC and~~under the ~~acquisition of various mineral and royalty interests for an aggregate purchase price of approximately $28.1 million.~~

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~~Predecessor Credit Facility~~

~~On January 31, 2014, our Predecessor entered into a credit agreement with Frost Bank for a $50.0 million credit facility. The~~secured revolving credit facility ~~was subject~~and $55.3 million of available capacity (or approximately $130.3 million if aggregate commitments were equal to our current borrowing base restrictions and was collateralized by certain properties. The borrowing base was $20 million with interest payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans. As of December 31, 2016, our Predecessor’s total indebtedness under its credit facility was approximately $10.6 million, with an average interest rate of 3.39%base). ~~The credit facility was to mature in January 2018. The credit facility contained certain restrictive covenants. As of December 31, 2016, the Predecessor was~~We were in compliance with all ~~of the~~ covenants included in the ~~credit facility. On February 8, 2017, our Predecessor repaid the entire outstanding principal and interest balance on the~~secured revolving credit facility ~~with cash proceeds from the contribution~~as of September 30, 2020.

For additional information on our ~~Predecessor’s mineral and royalty interests~~secured revolving credit facility, please read Note 8―Long-Term Debt to the ~~Partnership. We did not assume any indebtedness of our Predecessor~~unaudited condensed consolidated financial statements included in ~~connection with the IPO.~~this Quarterly Report.

~~Internal Controls and Procedures~~

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes‑Oxley Act of 2002 (“Sarbanes-Oxley Act”), and are therefore not required to make a formal assessment of the effectiveness of our internal controls over financial reporting for that purpose. We are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes‑Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2018. To comply with the requirements of being a public company, we will need to implement additional controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm is not yet required to attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the Jumpstart Our Business Act (“JOBS Act”) or as long as we are a non‑accelerated filer.

New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. However, we chose to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non‑emerging growth companies. Our election to “opt out” of the extended transition period is irrevocable.

The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies ~~within the historical~~to our unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report.

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Critical Accounting Policies and Related Estimates

~~The discussion and analysis of our financial condition and results of operations are based upon the historical financial statements of our Predecessor, which~~There have been ~~prepared in accordance with GAAP. Certain of~~no substantial changes to our critical accounting policies ~~involve judgments~~ and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accountingrelated estimates including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

~~See the notes to~~from those previously disclosed in our ~~and our Predecessor’s unaudited consolidated financial statements included elsewhere in this Quarterly~~Annual Report ~~for additional information regarding these accounting policies.~~

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~~Inflation~~

~~Inflation in the United States has been relatively low in recent years and did not have a material impact~~ on ~~our or our Predecessor’s results of operations~~Form 10-K for the ~~period from January 1, 2016 through September 30, 2017.~~year ended December 31, 2019.

~~Off‑Balance~~Contractual Obligations and Off-Balance Sheet Arrangements

~~As of September 30, 2017, neither we, nor our Predecessor had any off‑balance sheet arrangements other than operating leases. As of September 30, 2017, there~~There have been no significant changes to our contractual obligations previously disclosed in ~~the Partnership’s~~our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2019. As of September 30, 2020, we did not have any off-balance sheet arrangements other than operating leases. See Note 7—Leases to the unaudited condensed consolidated financial statements for additional information regarding our operating leases.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect ~~this volatility~~commodity prices to ~~continue~~be even more volatile in the ~~future.~~future as a result of COVID-19, ongoing international supply and demand imbalances and limited international storage capacity. The prices that our operators receive for production depend on many factors outside of our or their control. ~~Currently,~~To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparty to the contracts is an unrelated third party.

Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume.

Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. See Note 4—Derivatives to the unaudited condensed consolidated financial statements for additional information regarding our commodity derivatives.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not ~~have any commodity hedges in place but may~~require our counterparties to our derivative contracts to post collateral, we do ~~so in~~evaluate the ~~future if the Board~~credit standing of ~~Directors decides doing so~~such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of September 30, 2020, we had one counterparty to our derivative contracts, which is ~~in the best interest~~also one of the ~~Partnership.~~

~~Credit Risk~~lenders under our secured revolving credit facility.

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of September 30, ~~2017,~~2020, we had total borrowings outstanding under our secured revolving credit facility of ~~$22.2~~$169.7 million. The impact of a 1% increase in the

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interest rate on this amount of debt would result in an increase in interest expense of approximately ~~$0.2~~$1.7 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule ~~13a‑15(b)~~13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules ~~13a‑15(e)~~13a-15(e) and ~~15d‑15(e)~~15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the ~~SEC.~~U.S. Securities and Exchange Commission. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, ~~2017.~~2020.

Remediation of Material Weakness

As previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019, we identified a material weakness in our internal control over financial reporting during the preparation of such report. We lacked sufficient oversight of our full cost ceiling calculation, which is a component of our financial reporting requirements. During the second quarter of 2020, we completed the implementation of the procedures and controls to remediate this material weakness, which consisted of installing redundant levels of internal review of the full cost ceiling calculation prior to review by our independent registered public accounting firm.

In addition, during the second quarter of 2020, we completed our testing of effectiveness of the implemented procedures and controls and found them to be effective. As a result, we concluded that the material weakness had been remediated as of June 30, 2020.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, ~~2017~~2020 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a description of the Partnership’s legal proceedings, see Note 16—Commitments and Contingencies to the unaudited condensed consolidated financial statements, which is incorporated by reference herein.

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition, cash flows or results of operations.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the risks under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our ~~2016~~ Annual Report on Form ~~10-K. There have been no material changes to~~10-K for the year ended December 31, 2019, which risk factors ~~previously~~could also be affected by the potential effects of the outbreak of COVID-19 discussed ~~in Item 1A—Risk Factors in the Partnership’s 2016 Form 10-K.~~below. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

The ongoing COVID-19 outbreak and the related impact on oil and natural gas prices have adversely affected, and could continue to adversely affect, our business, financial condition and results of operations.

The ongoing COVID-19 outbreak, which the WHO declared a pandemic and the United States Government declared a national emergency in March 2020, has reached more than 200 countries and has continued to be a rapidly evolving situation. The pandemic has resulted in widespread adverse impacts on the global economy and financial markets, including record economic contraction in the United States, and we and our third-party operators and other parties with whom we have business relations have experienced disrupted business operations as a result. For example, in mid-March, we had to limit access to our administrative offices and took certain other precautionary measures intended to help minimize the risk to our employees, our business and our community. Beginning in mid-May, we opened our offices to employees on a voluntary basis, with employees having the option to work from the office or from home. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. While shelter-in-place restrictions subsided in the third quarter of 2020, the possibility of future restrictions remains as certain jurisdictions have begun re-opening only to face increases in new COVID-19 cases. In addition, our employees have the option to work remotely, which could increase the risk of security breaches or other cyber-incidents or attacks, loss of data, fraud and other disruptions.

The impact of the pandemic, including the resulting significant reduction in global demand for oil and, to a lesser extent natural gas, coupled with the sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, has led to significant global economic contraction generally and in our industry in particular. Although OPEC finalized an agreement in April 2020 to cut oil production by 9.7 million barrels per day during May and June 2020, and agreed in June 2020 to extend such production cuts until the end of July 2020, crude oil prices have remained depressed as a result of an increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. Oil and natural gas prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil and natural gas inventories, industry demand and economic performance are reported. The current price environment has caused some of our operators’ wells to become uneconomic, which has resulted, and may result in the future, in suspension of production from those wells or a significant reduction in, or no royalty revenues from, existing production. Some operators may also attempt to shut in producing wells and avoid lease termination or payment of shut-in royalties by claiming force majeure, if provided for in the applicable lease. The curtailment of production or the shut-in of wells as a result of the ongoing COVID-19 outbreak and the drop in oil prices are both outside of our control, and the materialization of either circumstance could have a significant impact on our result of operations. For example, in April 2020, we received notices from two operators regarding well shut-ins and curtailments of production on properties in which we own an interest. The properties were primarily located in the Eagle Ford Shale, and the production attributable to such properties on a Boe/d basis (6:1) represented approximately one percent of our total production for the first quarter of 2020. We received subsequent notice that the curtailment on all Eagle Ford Shale production has ceased and production resumed, effective September 1, 2020. We also received notifications of well shut-ins and curtailment in the second quarter of 2020

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from additional operators, and the production attributable to such properties on a Boe/d basis (6:1) accounted for less than one percent of our total production for the second quarter of 2020. We expect we will receive additional notices regarding well shut-ins and curtailments of production from our operators as depressed prices for oil and natural gas resulting from the COVID-19 outbreak, reductions in global demand and storage capacity issues continue.

Due to the recent significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, we recorded an impairment on our oil and natural gas properties of $22.2 million and $158.7 million for the three and nine months ended September 30, 2020, respectively. Due to the expected significant decline in the average of the trailing twelve month first-of-month pricing used in the full-cost ceiling test, we expect to record an impairment to our oil and natural gas properties in the fourth quarter of 2020 as a result of the full-cost ceiling limitation. If the expected significant decline in the price of oil, natural gas and NGLs continues through future periods or if prices decrease further in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.

In addition, it is possible that the borrowing base of our secured revolving credit facility will be reduced in the future as a result of a decrease in the value of the assets underlying the borrowing base in connection with a sustained decrease in oil and natural gas prices.

During the Board of Director’s determination of “available cash” for the third quarter of 2020, the Board of Directors approved the allocation of 25% of our cash available for distribution for the third quarter of 2020 for the repayment of $3.7 million in outstanding borrowings under our secured revolving credit facility. With respect to future quarters, the Board of Directors may continue to allocate cash generated by our business to the repayment of outstanding borrowings under our secured revolving credit facility or in other manners in which the Board of Directors determines to be appropriate at the time, and the Board of Directors may further change its policy with respect to cash distributions in the future.

To the extent that access to the capital and other financial markets is adversely affected by the effects of COVID-19 and energy prices generally, we may need to consider alternative sources of funding for our future acquisitions, which may increase our cost of, as well as adversely impact our access to, capital or otherwise impact our ability to complete acquisitions. We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments beyond our control, which are highly uncertain and cannot be predicted, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development and availability of effective treatments and vaccines, the duration of the outbreak, future actions taken by members of OPEC and other foreign oil-exporting countries, actions taken by governmental authorities, third-party operators and other third parties and the timing and extent to which normal economic and operating conditions resume.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On September 8, 2020, we issued 863,120 common units to Haymaker Management, LLC in exchange for 863,120 OpCo Common Units and an equal number of Class B Units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018 (the “Exchange Agreement”), by and among Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, the Kimbell Art Foundation, us, the General Partner, the Operating Company and the other holders of OpCo Common Units and Class B Units from time to time party thereto.

On September 21, 2020, we issued 1,498,280 common units to Springbok Energy Partners II Holdings, LLC in exchange for 1,498,280 OpCo Common Units and an equal number of Class B Units pursuant to the terms of the Exchange Agreement.

The issuance of each of the foregoing securities was exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), in reliance upon Section 4(a)(2) of the Securities Act.

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Item 6. Exhibits

~~The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report and is incorporated herein by reference.~~

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~~EXHIBIT INDEX~~

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form ~~S‑1~~S-1 (File No. ~~333‑215458)~~333-215458) filed on January 6, 2017)
3.2	—	~~First~~Third Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of ~~February 8, 2017~~September 23, 2018 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form ~~8‑K~~8-K filed ~~on February 14, 2017)~~September 25, 2018)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit ~~3.2~~3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form ~~S‑1~~S-1 (File No. ~~333‑215458)~~333-215458) filed on January 6, 2017)
3.4	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form ~~8‑K~~8-K filed on February 14, 2017)
3.5	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)
31.1*	—	Certification of Chief Executive Officer pursuant to Rule ~~13a‑14(a)~~13a-14(a)/~~15d‑14(a)~~15d-14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule ~~13a‑14(a)~~13a-14(a)/~~15d‑14(a)~~15d-14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to ~~18.~~18 U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to ~~18.~~18 U.S.C. Section 1350
101.INS**	—	Inline XBRL Instance ~~Document.~~Document —the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH**	—	Inline XBRL Taxonomy Extension Schema Document
101.CAL**	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	—	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	—	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*	—filed herewith

**	—furnished herewith

* —filed herewith

** —furnished herewith

3341

Table of Contents

~~SIGNATURES~~

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner

Date: November ~~9, 2017~~5, 2020	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: November ~~9, 2017~~5, 2020	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer

3442


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

For the quarterly period ended September 30, ~~2017~~2020 OR

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to


Title of each class:	Trading symbol(s)	Name of exchange on which registered:
Common Units Representing Limited Partner Interests	KRP	New York Stock Exchange


Large accelerated filer ☐	☐	Accelerated filer ☐	~~Non‑accelerated~~☒
Non-accelerated filer ☒ (Do not check if a smaller reporting company)	☐	Smaller reporting company ☐	☒
Emerging growth company	☒


PART I – FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited):	1
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Operations	2
Condensed Consolidated Statements of Changes in ~~Partners’ Capital and Predecessor Members’~~Unitholders’ Equity	3
Condensed Consolidated Statements of Cash Flows	4 5
Notes to Condensed Consolidated Financial Statements	5 6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16 19
Item 3. Quantitative and Qualitative Disclosures About Market Risk	31 37
Item 4. Controls and Procedures	31
	38


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	32 39
Item 1A. Risk Factors	32 39
Item ~~6. Exhibits~~ 2. Unregistered Sales of Equity Securities and Use of Proceeds	32 40
~~Signatures~~Item 6. Exhibits	34 41
Signatures	42


	September 30,		December 31,
	2020		2019
ASSETS
Current assets
Cash and cash equivalents	$	12,347,689	$	14,204,250
Oil, natural gas and NGL receivables		16,039,385		19,170,762
Commodity derivative assets		—		687,933
Accounts receivable and other current assets		946,937		76,868
Total current assets		29,334,011		34,139,813
Property and equipment, net		1,166,660		1,327,057
Investment in affiliate (equity method)		4,707,165		2,952,264
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($235,028,364 and $275,041,784 excluded from depletion at September 30, 2020 and December 31, 2019, respectively)		1,148,983,401		1,033,355,017
Less: accumulated depreciation, depletion and impairment		(523,403,235)		(328,913,425)
Total oil and natural gas properties, net		625,580,166		704,441,592
Right-of-use assets, net		3,194,116		3,399,634
Commodity derivative assets		—		116,568
Loan origination costs, net		1,469,266		2,217,126
Total assets	$	665,451,384	$	748,594,054

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	995,574	$	1,207,736
Other current liabilities		5,842,811		4,231,579
Commodity derivative liabilities		992,299		—
Total current liabilities		7,830,684		5,439,315
Operating lease liabilities, excluding current portion		2,919,194		3,124,416
Commodity derivative liabilities		2,699,576		—
Long-term debt		169,700,653		100,135,477
Total liabilities		183,150,107		108,699,208
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (55,000 and 110,000 units issued and outstanding as of September 30, 2020 and December 31, 2019, respectively)		42,050,637		74,909,732
Unitholders' equity:
Common units (38,948,023 units issued and outstanding as of September 30, 2020 and 23,518,652 units issued and outstanding as of December 31, 2019)		325,048,170		282,549,841
Class B units (20,779,781 units issued and outstanding as of September 30, 2020 and 25,557,606 units issued and outstanding as of December 31, 2019)		1,038,989		1,277,880
Total unitholders' equity		326,087,159		283,827,721
Noncontrolling interest		114,163,481		281,157,393
Total equity		440,250,640		564,985,114
Total liabilities, mezzanine equity and unitholders' equity	$	665,451,384	$	748,594,054


Delaware (State or other jurisdiction of incorporation or organization)	1311 (Primary Standard Industrial Classification Code Number)	~~47‑5505475~~47-5505475 (I.R.S. Employer Identification No.)


	Partnership		Predecessor
	September 30,		December 31,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	6,226,479	$	505,880
Oil, natural gas and NGL receivables		5,501,513		474,103
Other current assets		258,785		344,368
Total current assets		11,986,777		1,324,351
Property and equipment, net		204,343		261,568
Oil and natural gas properties
Oil and natural gas properties, using full-cost method of accounting		285,043,287		70,888,121
Less: accumulated depreciation, depletion, accretion and impairment		(11,047,641)		(51,948,355)
Total oil and natural gas properties		273,995,646		18,939,766
Deposits on oil and natural gas properties		3,949,000		—
Loan origination costs, net		270,833		13,046
Total assets	$	290,406,599	$	20,538,731

LIABILITIES AND PARTNERS' CAPITAL (PREDECESSOR MEMBERS' EQUITY)
Current liabilities
Accounts payable	$	152,569	$	1,030,862
Other current liabilities		2,146,834		112,508
Asset retirement obligations		—		27,013
Total current liabilities		2,299,403		1,170,383
Asset retirement obligations		—		14,468
Other liabilities		—		123,158
Long-term debt		22,214,090		10,598,860
Total liabilities		24,513,493		11,906,869
Commitments and contingencies
Predecessor members' equity		—		8,631,862
Partners' capital		265,893,106		—
Total liabilities and partners' capital (predecessor members' equity)	$	290,406,599	$	20,538,731


	Nine Months Ended September 30, 2020
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Balance at January 1, 2020		23,518,652	$	282,549,841		25,557,606	$	1,277,880	$	281,157,393	$	564,985,114
Common units issued for equity offering		5,000,000		73,601,668		—		—		—		73,601,668
Conversion of Class B units to common units		4,913,559		75,578,037		(4,913,559)		(245,678)		(75,578,037)		(245,678)
Redemption of Series A preferred units		—		(16,150,018)		—		—		(9,697,873)		(25,847,891)
Unit-based compensation		946,638		2,107,587		—		—		—		2,107,587
Distributions to unitholders		—		(11,122,088)		—		—		(9,616,966)		(20,739,054)
Distribution and accretion on Series A preferred units		—		(1,922,344)		—		—		(1,154,340)		(3,076,684)
Distribution on Class B units		—		(24,807)		—		—		—		(24,807)
Net loss		—		(37,353,883)		—		—		(22,430,516)		(59,784,399)
Balance at March 31, 2020		34,378,849		367,263,993		20,644,047		1,032,202		162,679,661		530,975,856
Units issued for Springbok Acquisition		2,224,358		13,257,174		2,497,134		124,857		14,758,062		28,140,093
Restricted units used for tax withholding		(1,018)		(6,259)		—		—		—		(6,259)
Forfeiture of restricted units		(14,166)		(106,245)		—		—		—		(106,245)
Unit-based compensation		—		2,534,198		—		—		—		2,534,198
Distributions to unitholders		—		(6,234,957)		—		—		(3,934,000)		(10,168,957)
Distribution and accretion on Series A preferred units		—		(966,609)		—		—		(611,359)		(1,577,968)
Distribution on Class B units		—		(23,141)		—		—		—		(23,141)
Net loss		—		(47,038,901)		—		—		(29,751,149)		(76,790,050)
Balance at June 30, 2020		36,588,023		328,679,253		23,141,181		1,157,059		143,141,215		472,977,527
Conversion of Class B units to common units		2,361,400		16,487,288		(2,361,400)		(118,070)		(16,487,288)		(118,070)
Forfeiture of restricted units		(1,400)		(12,614)		—		—		—		(12,614)
Unit-based compensation		—		2,446,329		—		—		—		2,446,329
Distributions to unitholders		—		(4,756,443)		—		—		(3,008,356)		(7,764,799)
Distribution and accretion on Series A preferred units		—		(1,028,981)		—		—		(548,987)		(1,577,968)
Distribution on Class B units		—		(23,141)		—		—		—		(23,141)
Net loss		—		(16,743,521)		—		—		(8,933,103)		(25,676,624)
Balance at September 30, 2020		38,948,023	$	325,048,170		20,779,781	$	1,038,989	$	114,163,481	$	440,250,640


	Units		Total
Members' equity - December 31, 2016 (Predecessor)		604,137	$	8,631,862

Unit-based compensation		—		50,422

Net loss		—		(496,856)

Transfer of membership units to Rivercrest Royalties Holdings, LLC		(604,137)		(98,988)


Partners' capital - February 8, 2017 (Partnership)		—		8,086,440

Common units issued to Predecessor in exchange for oil and natural gas properties		1,191,974		—

Common units issued to contributors in exchange for oil and natural gas properties		9,390,734		169,033,212

Common units sold to public		5,750,000		103,500,000

Underwriting discount and structuring fee incurred at initial public offering		—		(7,245,000)

Distributions to unitholders		—		(8,705,333)

Unit-based compensation		177,091		569,889

Net income		—		653,898

Partners' capital - September 30, 2017		16,509,799	$	265,893,106


		Weighted		Weighted		Weighted
		Average		Average		Average
		Grant-Date		Market-Date		Remaining
		Fair Value		Fair Value		Contractual
	Units	per Unit		per Unit		Term
Unvested at February 8, 2017	—	$	—	$	—	—
Granted - service condition employees	143,318		18.655		—	—
Granted - service condition consultants	24,253		—		15.780	—
Granted - non-employee directors	9,520				15.780
Vested	(9,520)		—		—	—
Forfeited	—		—		—	—
Exercised	—		—		—	—
Unvested at September 30, 2017	167,571	$	18.655	$	15.780	1.616 years


		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2019	739,479	$	18.059	1.335 years
Awarded	946,638		11.540	—
Vested	(160,155)		18.826	—
Forfeited	(15,566)		14.097	—
Unvested at September 30, 2020	1,510,396	$	13.933	1.909 years


	For the three months ended September 30,				For the nine months ended September 30,
EIA Average Price:	2017		2016		2017		2016
Oil (Bbl)	$	48.18	$	44.85	$	49.30	$	41.35
Natural gas (MMBtu)	$	2.95	$	2.88	$	3.01	$	2.34