Kimbell Royalty Partners 10Q 2020 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2020 OR

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

For the transition period from to

Commission file number: 001-38005

Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)


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

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

(817) 945-9700

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

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


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

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

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

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


Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☒
Emerging growth company	☒

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

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

As of October 30, 2020, the registrant had outstanding 38,948,023 common units representing limited partner interests and 20,779,781 Class B units representing limited partner interests.

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS


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 Unitholders’ Equity	3
Condensed Consolidated Statements of Cash Flows	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	38


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

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	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

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 OPERATIONS

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenue
Oil, natural gas and NGL revenues	$	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		1,840,607		2,236,405		4,916,858		5,757,742
Depreciation and depletion expense		10,704,945		15,098,107		36,002,109		37,690,558
Impairment of oil and natural gas properties		22,237,131		34,880,071		158,698,835		65,828,980
Marketing and other deductions		2,511,919		2,332,010		6,692,850		5,938,093
General and administrative expense		6,110,846		5,694,534		19,500,306		17,248,399
Total costs and expenses		43,405,448		60,241,127		225,810,958		132,463,772
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		(1,603,006)		(1,468,419)		(4,689,907)		(4,332,633)
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 and distributions and accretion on Series A preferred units 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)

Net loss attributable to common units
Basic	$	(0.50)	$	(0.73)	$	(3.13)	$	(1.53)
Diluted	$	(0.50)	$	(0.73)	$	(3.13)	$	(1.53)
Weighted average number of common units outstanding
Basic		35,423,112		22,399,748		33,540,977		20,715,633
Diluted		35,423,112		22,399,748		33,540,977		20,715,633

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 CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)


	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

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY – (Continued)

(Unaudited)


	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)


	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, references to “Kimbell Royalty Partners, LP,” the “Partnership,” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. References to “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.

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP is 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, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGL”) 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 properties in which it owns an interest.

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange 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 Annual Report on Form 10-K for the year ended December 31, 2019, which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the General Partner, the unaudited interim condensed consolidated financial statements contain all adjustments necessary to fairly present the financial position and results of operations for the interim periods in accordance with 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.

Preparation of 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.

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.

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

The global spread of coronavirus (“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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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, the Partnership’s oil, natural gas, and NGL operators and other parties with whom the Partnership has 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 the Organization of Petroleum Exporting Countries (“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.

The Partnership has 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, the Partnership restricted access to its offices to only essential employees, and directed the remainder of its employees to work from home to the extent possible. Beginning in mid-May, the Partnership opened its offices to employees on a voluntary basis, with employees having the option to work from the office or from home. These restrictions have had minimal impact on the Partnership’s operations to date and have allowed the Partnership to maintain the engagement and connectivity of its personnel, as well as minimize the number of employees in the office.

The ultimate impacts of COVID-19 and the volatility currently being experienced in the oil and natural gas markets on the Partnership’s business, cash flows, liquidity, financial condition and results of 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 of effective treatments, 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 and actions announced by OPEC and other foreign, oil-exporting countries, see Part I, Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 1A Risk Factors.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the nine months ended September 30, 2020, other than those discussed below in Recently Adopted Accounting Pronouncements.

New Accounting Pronouncements

Recently Adopted Pronouncements

In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement.” This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. The Partnership adopted this update on January 1, 2020 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the three and nine months ended September 30, 2020.

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard replaced the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The Partnership

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adopted this update using the modified retrospective approach, effective January 1, 2020. The adoption of this update did not have a material impact on the Partnership’s results of operations for the three and nine months ended September 30, 2020.

Accounting Pronouncements Not Yet Adopted

In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

NOTE 3—ACQUISITIONS AND JOINT VENTURES

Acquisitions

On March 25, 2019, the Partnership acquired 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 aggregate consideration for the Phillips Acquisition consisted of 9,400,000 common units of the Operating Company (“OpCo common units”) and an equal number of Class B units representing limited partner interests of the Partnership (“Class B units”). The Class B units and OpCo common units are exchangeable together into an equal number of common units representing limited partner interests in the Partnership (“common units”). The assets acquired in the Phillips Acquisition consisted of approximately 866,528 gross acres and 12,210 net royalty acres.

On September 20, 2019, the Partnership agreed to acquire various mineral and royalty interests in Oklahoma for an aggregate purchase price of approximately $9.9 million. The acquisition closed on November 6, 2019. The Partnership funded the payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired consisted of approximately 279,680 gross acres and 186 net royalty acres.

On April 17, 2020, the Partnership and the Operating Company completed the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”). The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, which was funded by borrowings under the Partnership’s secured revolving credit facility, (ii) the issuance of 2,224,358 common units and (iii) the issuance of 2,497,134 OpCo common units and an equal number of Class B units. At the time of the Springbok Acquisition, the acreage acquired had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other leading basins.

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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 Springbok Operating Company, LLC are affiliated with the entities acquired as part of the Springbok Acquisition, none of the 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 similar 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. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas 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 September 30, 2020, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The Partnership hedges its daily production based on the 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 contract period, and its 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.

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The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. The Partnership records all derivative contracts at fair value. Changes in the fair values of the Partnership’s derivative instruments are recognized as gains or losses in the current period and are presented on a net basis in the accompanying unaudited condensed consolidated statements of 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 Partnership’s open commodity derivative contracts consisted of the following:

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 NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the unaudited condensed consolidated balance sheets approximated fair value as of September 30, 2020 and December 31, 2019 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below.

●

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

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●

Level 2—Quoted prices for similar assets or liabilities in non-active markets, or inputs that are observable for the asset or liability, either directly or 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).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not 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 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 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 following factors, among others: economic and market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved

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reserves; and the 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 associated leasehold costs are transferred to the full cost pool and 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 first quarter of 2020 as a result of this impairment assessment. The transfer resulted in an additional ceiling test impairment expense for the nine months ended September 30, 2020 equal to the amount of the transfer. There were no additional impairments to unevaluated properties in the second or 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 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 recorded an impairment on its oil and natural gas properties of $34.9 million and $65.8 million during the three and nine months ended September 30, 2019, respectively, primarily due to a decline in the 12-month average price of oil and natural gas.

NOTE 7—LEASES

Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the 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 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 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 are the main office spaces used for operations. In July 2019, the Partnership became the lessee in several other related lease agreements for additional office space. In addition, the Partnership was involved in the construction and design of the underlying assets.

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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 8—LONG-TERM DEBT

The Partnership maintains a secured revolving credit facility that is secured by substantially all of its assets, the Operating Company’s assets and the assets of 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. Total commitments under the secured revolving credit facility 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 $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 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, breach of covenants, materially incorrect representations, 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, 2020, the Partnership’s outstanding balance was $169.7 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of September 30, 2020.

As of September 30, 2020, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.50% or Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.50%. For the nine months ended September 30, 2020, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.38%.

NOTE 9—PREFERRED UNITS

In July 2018, the 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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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 30% discount to the issue price, subject to 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 (iii) the Series A issue price plus accrued and unpaid distributions.

For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the July 12, 2018 (the “Series A Issuance Date”), a 13.0% internal rate of return with respect to the 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 12, 2020, the Partnership completed the redemption of 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. 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 pursuant to the exercise of the underwriters’ option to purchase additional common units. The Partnership did not receive any proceeds from the sale of the common units by the selling unitholders.

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The following table summarizes the changes in the number of the 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 common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the 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 following table summarizes the changes in the number of the Partnership’s 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

For each Class B unit issued, 5 cents has been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B units, are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units but prior to distributions on the common units and OpCo common units.

The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

NOTE 11—EARNINGS (LOSS) PER 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 restricted units granted under the Partnership’s LTIP for its employees, directors and consultants and potential conversion of Class B units.

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The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted earnings (loss) per unit:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Net loss attributable to common units	$	(17,795,643)	$	(16,261,051)	$	(105,125,328)	$	(31,706,677)

Weighted average number of common units outstanding:
Basic		35,423,112		22,399,748		33,540,977		20,715,633
Effect of dilutive securities:
Series A preferred units		—		—		—		—
Class B units		—		—		—		—
Restricted units		—		—		—		—
Diluted		35,423,112		22,399,748		33,540,977		20,715,633

Net loss attributable to common units
Basic	$	(0.50)	$	(0.73)	$	(3.13)	$	(1.53)
Diluted	$	(0.50)	$	(0.73)	$	(3.13)	$	(1.53)

The calculation of diluted net loss per unit for the three and nine months ended September 30, 2020 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 1,510,396 of unvested restricted units because their inclusion in the calculation would be anti-dilutive. The calculation of diluted net loss per unit for the three and nine months ended September 30, 2019 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 975,540 unvested restricted units because their inclusion in the calculation would be anti-dilutive.

NOTE 12—INCOME TAXES

In May 2018, the Board of Directors unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items.

Prior to September 24, 2018, the Partnership was organized as a pass-through entity for income tax purposes. As a result, the Partnership’s partners were responsible for federal and state income or similar taxes on their share of the Partnership’s taxable income with the exception of any entity-level income or similar taxes such as the Texas Franchise Tax. The Partnership recorded a benefit from income taxes of $0.7 million for both the three and nine months ended September 30, 2020. The benefit recorded by the Partnership for the three and nine months ended September 30, 2020 primarily related to the filing of its 2019 federal and state income tax returns in September 2020, which resulted in a true-up of previously recorded income tax expense.

NOTE 13—UNIT-BASED COMPENSATION

On September 23, 2018, the General Partner entered into the First Amendment to the LTIP, which increased the number of common units eligible for issuance under the LTIP by 2,500,000 common units for a total of 4,541,600 common units. The Partnership’s LTIP authorizes grants to its employees, directors and consultants. The restricted units issued under the Partnership’s LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants is treated in the same manner as that of the employees and directors.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Distributions related to the restricted units are paid concurrently with the Partnership’s distributions for common units. The fair value of the Partnership’s restricted units issued under the LTIP to the Partnership’s employees, directors and consultants is determined by utilizing the market value of the Partnership’s common units on the respective grant date. The following table presents a summary of the Partnership’s unvested restricted units.


		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

NOTE 14—RELATED PARTY TRANSACTIONS

The Partnership currently has a management services agreement with Kimbell Operating, which has separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”), pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors may identify, evaluate and recommend to the Partnership 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 the Partnership’s unitholders.

During the three and nine months ended September 30, 2020, 0 monthly services fee was paid to BJF Royalties. During the three months ended September 30, 2020, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $30,000, $66,054 and $140,364, respectively. During the nine months ended September 30, 2020, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $90,000, $198,162 and $421,092, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s LTIP.

NOTE 15—ADMINISTRATIVE SERVICES

Management Services Agreement

The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business operations. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. See Note 14―Related Party Transactions.

Transition Services Agreement

In connection with the Springbok Acquisition, the Partnership entered into a Transition Services Agreement (the “Transition Services Agreement”) with Springbok Investment Management, LP (“SIM”). Pursuant to the Transition Services Agreement, SIM provided certain administrative services and accounting assistance on a transitional basis for total compensation of $300,000 from April 17, 2020 through June 17, 2020, at which point, the Transition Services Agreement terminated.

NOTE 16—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. Management is not aware of any legal,

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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 as of September 30, 2020.

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to September 30, 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 23, 2020, 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.

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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 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 (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Form 10-K”).

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” the “Partnership,” “we” or “us” refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to 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 to the Partnership.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements and information in this Quarterly Report may constitute forward-looking statements. 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 statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these 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 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 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 (“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;

●

industry, economic, business or 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 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 acquire an interest;

●

uncertainties with respect to identified drilling locations and estimates of 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;

●

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.

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 made, whether as a result of new information, future events or otherwise.

Overview

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 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 NGLs from the acreage underlying our interests, net of 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 from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of September 30, 2020, we owned mineral and royalty interests in approximately 9.0 million gross acres and overriding royalty interests in approximately 4.6 million gross acres, with approximately 60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of September 30, 2020, over 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 28 states and in every major onshore basin across the continental United States and include ownership in over 96,000 gross wells, including over 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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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 2020 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 did not receive any notification of shut-ins or curtailment in the third quarter of 2020. We expect that as the supply and 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 adverse effect on our business, cash flows, liquidity, financial condition and results of operations in the 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 impairment to our oil and natural gas properties in the fourth quarter of 2020 as a result of the full-cost ceiling limitation.

The ultimate impacts of COVID-19 and the volatility currently being experienced in the oil and natural gas markets on our business, cash flows, liquidity, financial condition and results of 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 this report.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. 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 prices. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (“EIA”).


	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, 2020, the West Texas Intermediate posted price for crude oil was $35.64 per Bbl and the Henry Hub spot market price of natural gas was $3.03 per MMBtu.

The following table, as reported by the EIA, sets forth the average daily prices for oil and natural 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 exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

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The Baker Hughes United States Rotary Rig count decreased by 69.1% from 860 active rigs as of September 30, 2019 to 266 active rigs as of September 30, 2020.

According to the Baker Hughes United States Rotary Rig count, rig activity in the 28 states in which we own mineral and royalty interests included 263 active rigs as of September 30, 2020 compared to 851 active rigs as of September 30, 2019. The decrease in rig count 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 by United States basins and producing regions for the 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 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. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

The following table presents the breakdown of our 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 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.

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Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution

Adjusted EBITDA and cash available for distribution are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution are useful because 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), net of 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 and depletion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by 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 loss and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated (unaudited).


	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		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
EBITDA		(14,063,537)		(12,245,065)		(122,253,921)		(11,991,449)
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
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		902,448		611,885		2,474,715		1,819,003
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

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	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 Our Historical Results

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

Ongoing Acquisition Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our 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 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”).

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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 acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the 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 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.

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, 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 on such properties for the three months ended March 31, 2020. We similarly recorded an impairment on the value of our unevaluated oil and natural gas properties for the three months ended March 31, 2020, which primarily were acquired in various acquisitions since our initial public offering. There were no additional impairments to unevaluated properties in the second or third quarters of 2020.

As a result of our full cost ceiling analysis, we recorded an impairment on our 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.

We recorded an impairment on our oil and natural gas properties of $34.9 million and $65.8 million during the three and nine months ended September 30, 2019, respectively, primarily due to a decline in the 12-month average price of oil and natural gas.

As discussed in our Annual Report on Form 10-K for the year ended December 31, 2019, we do not intend to book proved undeveloped reserves going forward. As such, additional impairment charges could be recorded in connection

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with future acquisitions. Further, 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.

Results of Operations

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	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		1,840,607		2,236,405		4,916,858		5,757,742
Depreciation and depletion expense		10,704,945		15,098,107		36,002,109		37,690,558
Impairment of oil and natural gas properties		22,237,131		34,880,071		158,698,835		65,828,980
Marketing and other deductions		2,511,919		2,332,010		6,692,850		5,938,093
General and administrative expenses		6,110,846		5,694,534		19,500,306		17,248,399
Total costs and expenses		43,405,448		60,241,127		225,810,958		132,463,772
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		(1,603,006)		(1,468,419)		(4,689,907)		(4,332,633)
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)		362,363		298,907		1,060,957		794,471
Natural gas (Mcf)		4,601,729		5,412,002		13,283,208		12,778,885
Natural gas liquids (Bbls)		173,392		164,202		504,066		418,106
Combined volumes (Boe) (6:1)		1,302,710		1,365,109		3,778,891		3,342,391

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

Oil, Natural Gas and NGL Revenues

For the three months ended September 30, 2020, our oil, natural gas and NGL revenues were $24.3 million, a decrease of $5.2 million from $29.5 million for the three months ended September 30, 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 revenue primarily associated with the Springbok Acquisition.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,302,710 Boe or 14,160 Boe/d, for the three months ended September

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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, 2019. The decrease in production for the three months ended September 30, 2020 was partially offset by an increase in production primarily associated with the Springbok Acquisition, which accounted for 204,380 Boe or 2,222 Boe/d. Our production for the three months ended September 30, 2019 included a non-routine increase in production related to the recognition of unknown upside production associated with 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 $38.36 per Bbl of oil, $1.76 per Mcf of natural gas and $13.42 per Bbl of NGL for the volumes sold during the three months ended September 30, 2020 compared to $54.87 per Bbl of oil, $2.05 per Mcf of natural gas and $12.52 per Bbl of NGL for the volumes sold during the three months ended September 30, 2019. The three months ended September 30, 2020 decreased 30.1% or $16.51 per Bbl of oil and 14.1% or $0.29 per Mcf of natural gas as compared to the three months ended September 30, 2019. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 27.4% or $15.45 per Bbl of 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 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

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 of oil and natural gas contracts relative to the fixed-price in our open derivative contracts.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended September 30, 2020 were $1.8 million, a decrease of $0.4 million from $2.2 million for the three months ended September 30, 2019. The decrease in production and ad valorem taxes was primarily related to the significant decrease in the average prices we received for oil, natural gas and NGL production for the three months ended September 30, 2020.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended September 30, 2020 were $10.7 million, a decrease of $4.4 million from$15.1 million for the three months ended September 30, 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 basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $8.16 for the three months ended September 30, 2020, a decrease of $2.87 per barrel from the $11.03 average depletion rate per barrel for the three months ended September 30, 2019. The decrease in the depletion rate was due to the significant impairment that was recorded during the year ended December 31, 2019 and the 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

We 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, 2019 was primarily a result of a decline in the 12-month average price of oil and natural gas.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended September 30, 2020 were $2.5 million, an increase of $0.2 million from $2.3 million for the three months ended September 30, 2019, which was attributable to the Springbok Acquisition.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2020 were $6.1 million, an increase of $0.4 million from $5.7 million for the three months ended September 30, 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 a $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 for the three months ended September 30, 2020 was $1.6 million compared to $1.5 million for the three months ended September 30, 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, 2020 to the Nine Months Ended September 30, 2019

Oil, Natural Gas and NGL Revenues

For the nine months ended September 30, 2020, our oil, natural gas and NGL revenues were $66.7 million, a decrease of $13.6 million from $80.3 million for the nine months ended September 30, 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, 2020 as discussed below. This decrease was partially offset by an increase in production associated with various acquisitions throughout the 2019 and 2020 periods.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 3,778,891 Boe or 13,792 Boe/d, for the nine months ended September 30, 2020, an increase of 436,500 Boe or 1,549 Boe/d, from 3,342,391 Boe or 12,243 Boe/d, for the nine months ended September 30, 2019. The increase in production for the nine months ended September 30, 2020 was primarily attributable to production associated with the Springbok Acquisition, which accounted for 375,535 Boe or 2,249 Boe/d. Our production for the nine months ended September 30, 2019 included a non-routine increase in production related to the recognition of unknown upside production associated with the assets acquired in the Haymaker Acquisition, which accounted for 188,882 Boe or 2,053 Boe/d.

Our operators received an average of $36.08 per Bbl of oil, $1.70 per Mcf of natural gas and $11.47 per Bbl of NGL for the volumes sold during the nine months ended September 30, 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 volumes sold during the nine months ended September 30, 2019.

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

Lease Bonus and Other Income

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

Production and ad valorem taxes for the nine months ended September 30, 2020 were $4.9 million, a decrease of $0.9 million from $5.8 million for the nine months ended September 30, 2019. The decrease in production and ad valorem taxes was 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 $1.7 million from $37.7 million for the nine months ended September 30, 2019. The decrease in the depreciation and depletion expense was partially offset by the acquisition of various mineral and royalty interests in Oklahoma, the Buckhorn Acquisition, and the 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 basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $9.47 for the nine months ended September 30, 2020, a decrease of $1.79 per barrel from the $11.26 average depletion rate per barrel for the nine months ended September 30, 2019. The decrease in the depletion rate was due to the significant impairment that was recorded during the year ended December 31, 2019 and the 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

We recorded an impairment expense on our oil and natural gas properties of $158.7 million and $65.8 million during the nine months ended September 30, 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 Our Historical Results—Impairment of Oil and Natural Gas Properties.”

The impairment recorded for the nine months ended September 30, 2019 was primarily a result of a decline in the 12-month average price of oil and natural gas.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the nine months ended September 30, 2020 were $6.7 million, an increase of $0.8 million from $5.9 million for the nine months ended September 30, 2019. The increase in marketing and other deductions was primarily attributable to the Springbok Acquisition.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2020 were $19.5 million, an increase of $2.3 million from $17.2 million for the nine months ended September 30, 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 a $1.4 million increase in unit-based compensation expense and cash general and administrative expenses resulting from increases in salaries and wages and our costs associated with company growth.

Interest Expense

Interest expense for the nine months ended September 30, 2020 was $4.7 million compared to $4.3 million for the nine months ended September 30, 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. Total commitments under our secured revolving credit facility 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 $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, to be used for general partnership purposes, including working capital and acquisitions, among other things. As of October 30, 2020, we had an outstanding balance of $169.8 million under our secured revolving credit facility.

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 in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by 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 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 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 capital needs that the Board of Directors may determine is appropriate.

In light of the unprecedented global economic impact resulting from the COVID-19 pandemic, the related impact to the United States oil and natural gas markets and the 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 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.

We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may 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. 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, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

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 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.

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Cash Flows

The table below presents our cash flows for the periods indicated.


	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 operating cash flow is impacted by many variables, the most significant of which 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 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 control and are difficult to predict. Cash flows provided by operating activities for the nine months ended September 30, 2020 were $47.9 million, a decrease of $16.1 million compared to $64.0 million for the nine months ended September 30, 2019. The decrease in cash flows provided by operating activities was primarily attributable to the decrease in the average prices we received for oil, natural gas and NGL production for the nine months ended September 30, 2020.

Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2020 increased by $82.9 million compared to the nine months ended September 30, 2019. For the nine months ended September 30, 2020, we used $87.5 million primarily to fund the 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 connection with the Joint Venture during the period. For the nine months ended September 30, 2019, we used $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 in Oklahoma and $0.8 million to fund the remodel of our office space.

Financing Activities

Cash flows provided by financing activities were $39.1 million for the nine months ended September 30, 2020 compared to $53.5 million in cash flows used in financing activities for the nine months ended September 30, 2019. Cash flows provided by financing activities for the nine months ended September 30, 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 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 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 holders of 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 $0.5 million in contributions from our Class B unitholders.

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Capital Expenditures

During the nine months ended September 30, 2020, we paid approximately $87.5 million primarily in connection with the Springbok Acquisition. During the nine months ended September 30, 2019, we paid approximately $1.2 million in connection with the Phillips Acquisition and a $1.0 million deposit in connection with the acquisition of various mineral and royalty interests in Oklahoma.

Indebtedness

We maintain a secured revolving credit facility 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. Availability under our secured revolving credit facility equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base. Total commitments under our secured revolving credit facility 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 our secured revolving credit facility to be increased to 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 May 1, 2020 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $300.0 million and total commitments remained at $225.0 million. 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 of the lenders under the secured revolving credit facility do not change, until such reduction or series of 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, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. As of September 30, 2020, we had outstanding borrowings of $169.7 million under the secured revolving credit facility and $55.3 million of available capacity (or approximately $130.3 million if aggregate commitments were equal to our current borrowing base). We were in compliance with all covenants included in the secured revolving credit facility as of September 30, 2020.

For additional information on our secured revolving credit facility, please read Note 8―Long-Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report.

New and Revised Financial Accounting Standards

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

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Critical Accounting Policies and Related Estimates

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

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 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 commodity prices to be even more volatile in the 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. 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 require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of 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 also one of the 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, 2020, we had total borrowings outstanding under our secured revolving credit facility of $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 $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) 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) and 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 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, 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, 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.

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 Annual Report on Form 10-K for the year ended December 31, 2019, which risk factors could also be affected by the potential effects of the outbreak of COVID-19 discussed 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

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 (File No. 333-215458) filed on January 6, 2017)
3.2	—	Third Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 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 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)/15d-14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
101.INS*	—	Inline XBRL Instance 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

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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 5, 2020	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


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

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