UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM ~~10‑Q~~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, ~~2017~~2021 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~~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~~47-5505475 (I.R.S. Employer Identification No.)

777 Taylor Street, Suite 810

Fort Worth, Texas76102

~~(817) 945‑9700~~(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 ~~and posted on its corporate website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation ~~S‑T~~S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ 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~~☒
Non-accelerated filer ☒ (Do not check if a smaller reporting company)	☐	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~~12b-2 of the Exchange Act). Yes ☐ No ☒

As of ~~November 8, 2017, 16,509,799~~October 29, 2021, the registrant had outstanding 42,916,472 common units ~~of the registrant were outstanding.~~representing limited partner interests and 17,611,579 Class B units representing limited partner interests.

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

FORM ~~10‑Q~~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 ~~Partners’ Capital and Predecessor Members’~~Unitholders’ Equity	3
Condensed Consolidated Statements of Cash Flows	4 5
Notes to Condensed Consolidated Financial Statements	5 6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16 18
Item 3. Quantitative and Qualitative Disclosures About Market Risk	31 35
Item 4. Controls and Procedures	31
	36


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	32 37
Item 1A. Risk Factors	32 37
Item 6. Exhibits	32 38
Signatures	34 39

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,
	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	12,698,756	$	9,804,977
Oil, natural gas and NGL receivables		30,683,099		17,552,756
Accounts receivable and other current assets		1,495,525		973,956
Total current assets		44,877,380		28,331,689
Property and equipment, net		2,257,936		1,964,660
Investment in affiliate (equity method)		4,689,604		5,134,951
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($171,847,133 and $225,681,626 excluded from depletion at September 30, 2021 and December 31, 2020, respectively)		1,149,610,813		1,149,095,232
Less: accumulated depreciation, depletion and impairment		(652,252,233)		(628,102,279)
Total oil and natural gas properties, net		497,358,580		520,992,953
Right-of-use assets, net		2,921,796		3,123,454
Derivative assets		661,338		—
Loan origination costs, net		4,282,273		5,086,486
Total assets	$	557,048,907	$	564,634,193

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	1,028,487	$	888,735
Other current liabilities		6,317,566		4,765,161
Derivative liabilities		33,731,319		3,113,178
Total current liabilities		41,077,372		8,767,074
Operating lease liabilities, excluding current portion		2,639,197		2,848,452
Derivative liabilities		8,180,206		3,167,685
Long-term debt		192,709,601		171,550,142
Other liabilities		479,167		—
Total liabilities		245,085,543		186,333,353
Commitments and contingencies (Note 14)
Mezzanine equity:
Series A preferred units (25,000 units and 55,000 units issued and outstanding as of September 30, 2021 and December 31, 2020, respectively)		20,407,128		42,666,102
Unitholders' equity:
Common units (42,916,472 units and 38,918,689 units issued and outstanding as of September 30, 2021 and December 31, 2020, respectively)		270,527,661		257,593,307
Class B units (17,611,579 and 20,779,781 units issued and outstanding as of September 30, 2021 and December 31, 2020, respectively)		880,579		1,038,989
Total unitholders' equity		271,408,240		258,632,296
Noncontrolling interest		20,147,996		77,002,442
Total equity		291,556,236		335,634,738
Total liabilities, mezzanine equity and unitholders' equity	$	557,048,907	$	564,634,193

~~(Unaudited)~~

Partnership

Predecessor

September 30,

December 31,

2017

2016
ASSETS

Current assets

Cash and cash equivalents

$
6,226,479

$
505,880
Oil, natural gas and NGL receivables

5,501,513

474,103
Other current assets

258,785

344,368
Total current assets

11,986,777

1,324,351
Property and equipment, net

204,343

261,568
Oil and natural gas properties

Oil and natural gas properties, using full-cost method of accounting

285,043,287

70,888,121
Less: accumulated depreciation, depletion, accretion and impairment

(11,047,641)

(51,948,355)
Total oil and natural gas properties

273,995,646

18,939,766
Deposits on oil and natural gas properties

3,949,000

—
Loan origination costs, net

270,833

13,046
Total assets

$
290,406,599

$
20,538,731

LIABILITIES AND PARTNERS' CAPITAL (PREDECESSOR MEMBERS' EQUITY)

Current liabilities

Accounts payable

$
152,569

$
1,030,862
Other current liabilities

2,146,834

112,508
Asset retirement obligations

—

27,013
Total current liabilities

2,299,403

1,170,383
Asset retirement obligations

—

14,468
Other liabilities

—

123,158
Long-term debt

22,214,090

10,598,860
Total liabilities

24,513,493

11,906,869
Commitments and contingencies

Predecessor members' equity

—

8,631,862
Partners' capital

265,893,106

—
Total liabilities and partners' capital (predecessor members' equity)

$
290,406,599

$
20,538,731

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenue
Oil, natural gas and NGL revenues	$	47,638,423	$	24,325,893	$	122,844,684	$	66,686,729
Lease bonus and other income		1,722,508		15,916		3,013,041		313,844
(Loss) gain on commodity derivative instruments, net		(17,566,617)		(5,897,646)		(45,919,531)		193,995
Total revenues		31,794,314		18,444,163		79,938,194		67,194,568
Costs and expenses
Production and ad valorem taxes		3,104,502		1,840,607		8,100,733		4,916,858
Depreciation and depletion expense		8,828,517		10,704,945		25,076,429		36,002,109
Impairment of oil and natural gas properties		—		22,237,131		—		158,698,835
Marketing and other deductions		2,996,434		2,511,919		8,842,942		6,692,850
General and administrative expense		6,766,628		6,110,846		20,247,843		19,500,306
Total costs and expenses		21,696,081		43,405,448		62,267,947		225,810,958
Operating income (loss)		10,098,233		(24,961,285)		17,670,247		(158,616,390)
Other income (expense)
Equity income in affiliate		261,336		292,803		719,958		460,360
Interest expense		(2,495,465)		(1,603,006)		(6,692,263)		(4,689,907)
Other (expense) income		(397,608)		(100,000)		16,347		(100,000)
Net income (loss) before income taxes		7,466,496		(26,371,488)		11,714,289		(162,945,937)
Benefit from income taxes		—		(694,864)		—		(694,864)
Net income (loss)		7,466,496		(25,676,624)		11,714,289		(162,251,073)
Distribution and accretion on Series A preferred units		(4,849,996)		(1,577,968)		(8,005,932)		(6,232,620)
Net (income) loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests		(761,311)		9,482,090		(1,024,655)		63,429,454
Distribution on Class B units		(17,610)		(23,141)		(59,170)		(71,089)
Net income (loss) attributable to common units	$	1,837,579	$	(17,795,643)	$	2,624,532	$	(105,125,328)

Net income (loss) attributable to common units
Basic	$	0.04	$	(0.50)	$	0.07	$	(3.13)
Diluted	$	0.04	$	(0.50)	$	0.06	$	(3.13)
Weighted average number of common units outstanding
Basic		41,106,157		35,423,112		39,383,172		33,540,977
Diluted		42,619,472		35,423,112		41,112,824		33,540,977

~~(Unaudited)~~

Partnership

Predecessor

Partnership

Predecessor

Three Months Ended September 30,

Three Months Ended September 30,

Period from February 8, 2017 to September 30,

Period from January 1, 2017 to February 7,

Nine Months Ended September 30,

2017


2016

2017


2017

2016
Revenue

Oil, natural gas and NGL revenues

$
8,351,399

$
969,084

$
20,656,741

$
318,310

$
2,572,477
Costs and expenses

Production and ad valorem taxes

778,733

120,315

1,602,520

19,651

203,567
Depreciation, depletion and accretion expense

4,488,915

418,969

11,156,292

113,639

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

—

306,959

—

—

4,992,897
Marketing and other deductions

424,702

320,698

1,068,509

110,534

570,521
General and administrative expense

2,314,718

463,501

5,707,093

532,035

1,252,001
Total costs and expenses

8,007,068

1,630,442

19,534,414

775,859

8,263,009
Operating income (loss)

344,331

(661,358)

1,122,327

(457,549)

(5,690,532)
Other expense

Interest expense

225,302

103,596

468,429

39,307

314,081
Income (loss) before income taxes

119,029

(764,954)

653,898

(496,856)

(6,004,613)
State income taxes

—

4,212

—

—

13,401
Net income (loss)

$
119,029

$
(769,166)

$
653,898

$
(496,856)

$
(6,018,014)

Net income (loss) attributable to common units

Basic

$
0.01

$
(1.27)

$
0.04

$
(0.82)

$
(9.96)
Diluted

$
0.01

$
(1.27)

$
0.04

$
(0.82)

$
(9.96)
Weighted average number of common units outstanding

Basic

16,337,985

604,137

16,334,774

604,137

604,137
Diluted

16,503,664

604,137

16,434,385

604,137

604,137

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)


	Nine Months Ended September 30, 2021
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Balance at January 1, 2021		38,918,689	$	257,593,307		20,779,781	$	1,038,989	$	77,002,442	$	335,634,738
Restricted units repurchased for tax withholding		(85,360)		(923,587)		—		—		—		(923,587)
Unit-based compensation		936,567		2,692,494		—		—		—		2,692,494
Distributions to unitholders		—		(7,394,551)		—		—		(3,948,160)		(11,342,711)
Distribution and accretion on Series A preferred units		—		(1,036,432)		—		—		(541,536)		(1,577,968)
Distribution on Class B units		—		(20,780)		—		—		—		(20,780)
Net income		—		352,837		—		—		184,357		537,194
Balance at March 31, 2021		39,769,896		251,263,288		20,779,781		1,038,989		72,697,103		324,999,380
Conversion of Class B units to common units		3,168,202		40,482,756		(3,168,202)		(158,410)		(40,482,756)		(158,410)
Restricted units repurchased for tax withholding		(21,626)		(220,677)		—		—		—		(220,677)
Unit-based compensation		—		2,743,917		—		—		—		2,743,917
Distributions to unitholders		—		(10,732,033)		—		—		(5,610,542)		(16,342,575)
Distribution and accretion on Series A preferred units		—		(1,118,834)		—		—		(459,134)		(1,577,968)
Distribution on Class B units		—		(20,780)		—		—		—		(20,780)
Net income		—		2,630,942		—		—		1,079,657		3,710,599
Balance at June 30, 2021		42,916,472		285,028,579		17,611,579		880,579		27,224,328		313,133,486
Redemption of Series A preferred units		—		(5,794,919)		—		—		(2,378,054)		(8,172,973)
Unit-based compensation		—		2,760,528		—		—		—		2,760,528
Distributions to unitholders		—		(13,304,106)		—		—		(5,459,589)		(18,763,695)
Distribution and accretion on Series A preferred units		—		(3,438,814)		—		—		(1,411,182)		(4,849,996)
Distribution on Class B units		—		(17,610)		—		—		—		(17,610)
Net income		—		5,294,003		—		—		2,172,493		7,466,496
Balance at September 30, 2021		42,916,472	$	270,527,661		17,611,579	$	880,579	$	20,147,996	$	291,556,236

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

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

(Unaudited)

Units

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

604,137

$
8,631,862

Unit-based compensation

—

50,422

Net loss

—

(496,856)

Transfer of membership units to Rivercrest Royalties Holdings, LLC

(604,137)

(98,988)

Partners' capital - February 8, 2017 (Partnership)

—

8,086,440

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

1,191,974

—

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

9,390,734

169,033,212

Common units sold to public

5,750,000

103,500,000

Underwriting discount and structuring fee incurred at initial public offering

—

(7,245,000)

Distributions to unitholders

—

(8,705,333)

Unit-based compensation

177,091

569,889

Net income

—

653,898

Partners' capital - September 30, 2017

16,509,799

$
265,893,106


	Nine Months Ended September 30, 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

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

~~(Unaudited)~~

Partnership

Predecessor

Period from February 8, 2017 to September 30,

Period from January 1, 2017 to February 7,

Nine Months Ended September 30,


2017


2017

2016
CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss)

$
653,898

$
(496,856)

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

Depreciation, depletion and accretion expense

11,156,292

113,639

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

—

—

4,992,897
Amortization of loan origination costs

41,667

4,241

34,245
Amortization of tenant improvement allowance

—

(2,864)

(25,777)
Unit-based compensation

569,889

50,422

453,795
Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

(496,886)

14,551

11,258
Other current assets

(258,785)

333,056

1,246,269
Accounts payable

152,569

247,972

(1,071,453)
Other current liabilities

2,146,834

(77,442)

89,550
Net cash provided by operating activities

13,965,478

186,719

956,793
CASH FLOWS FROM INVESTING ACTIVITIES

Purchases of property and equipment

(57,592)

—

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

(3,949,000)

—

—
Purchase of oil and natural gas properties

(113,183,664)

(523)

(75,883)
Net cash used in investing activities

(117,190,256)

(523)

(93,899)
CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from initial public offering

96,255,000

—

—
Distributions to unitholders

(8,705,333)

—

—
Borrowings on long-term debt

22,214,090

—

—
Repayments on long-term debt

—

—

(550,000)
Payment of loan origination costs

(312,500)

—

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

109,451,257

—

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

6,226,479

186,196

299,894
CASH AND CASH EQUIVALENTS, beginning of period

—

505,880

379,741
CASH AND CASH EQUIVALENTS, end of period

$
6,226,479

$
692,076

$
679,635
Supplemental cash flow information:

Cash paid for interest

$
276,246

$
34,505

$
280,010
Cash paid for taxes

$
—

$
5,355

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

Capital expenditures through issuance of common units

$
176,404,698

$
—

$
—


	Nine Months Ended September 30,
	2021		2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	11,714,289	$	(162,251,073)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and depletion expense		25,076,429		36,002,109
Impairment of oil and natural gas properties		—		158,698,835
Amortization of right-of-use assets		221,294		205,518
Amortization of loan origination costs		1,148,066		808,534
Equity income in affiliate		(719,958)		(460,360)
Cash distribution from affiliate		664,916		—
Forfeiture of restricted units		—		(118,859)
Unit-based compensation		8,196,939		7,088,114
Loss on derivative instruments, net of settlements		34,969,324		4,496,376
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(13,130,343)		3,131,377
Accounts receivable and other current assets		(521,569)		(870,069)
Accounts payable		139,753		(212,162)
Other current liabilities		1,552,405		1,611,232
Operating lease liabilities		(228,891)		(205,222)
Net cash provided by operating activities		69,082,654		47,924,350
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(740,584)		(50,737)
Purchase of oil and natural gas properties		(515,582)		(87,488,292)
Investment in affiliate		—		(1,751,951)
Cash distribution from affiliate		500,389		457,410
Net cash used in investing activities		(755,777)		(88,833,570)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity offering		—		73,601,668
Redemption of Class B contributions on converted units		(158,410)		(363,747)
Redemption on Series A preferred units		(36,075,370)		(61,089,600)
Distributions to common unitholders		(31,430,690)		(22,113,488)
Distribution to OpCo unitholders		(15,018,291)		(16,559,322)
Distribution and accretion on Series A preferred units		(2,362,509)		(3,850,006)
Distribution on Class B units		(59,170)		(71,089)
Borrowings on long-term debt		40,559,459		157,065,176
Repayments on long-term debt		(19,400,000)		(87,500,000)
Payment of loan origination costs		(343,853)		(60,674)
Restricted units repurchased for tax withholding		(1,144,264)		(6,259)
Net cash (used in) provided by financing activities		(65,433,098)		39,052,659
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		2,893,779		(1,856,561)
CASH AND CASH EQUIVALENTS, beginning of period		9,804,977		14,204,250
CASH AND CASH EQUIVALENTS, end of period	$	12,698,756	$	12,347,689
Supplemental cash flow information:
Cash paid for interest	$	5,446,245	$	3,928,101
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties	$	—	$	28,140,093
Noncash effect of Series A preferred unit redemption	$	8,172,973	$	25,847,891
Non-cash deemed distribution to Series A preferred units	$	5,643,423	$	2,382,614
Recognition of tenant improvement asset	$	479,167	$	—
Right-of-use assets obtained in exchange for operating lease liabilities	$	19,636	$	—

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

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~~KIMBELL ROYALTY PARTNERS, LP~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

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

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

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

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements ~~of the Partnership~~ have been prepared in accordance with accounting principles generally accepted ~~accounting principles~~ in the United States (“GAAP”) for interim financial information and with the instructions to Form ~~10‑Q~~10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ~~(“SEC”~~(the “SEC”). As a result, the accompanying unaudited interim condensed consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim condensed consolidated financial statements and related notes should be read in conjunction with the Partnership’s ~~and the Predecessor’s financial statements for the years ended December 31, 2016 and 2015, which are included in the Partnership’s~~ Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2020 (the “2020 Form 10-K”), which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the ~~Partnership’s management,~~General Partner, the unaudited interim condensed consolidated financial statements contain all adjustments ~~of a normal recurring nature~~ necessary to fairly present the financial position and results of operations for the interim periods in accordance with ~~GAAP.~~GAAP and all adjustments are of a normal recurring nature. All material intercompany balances and transactions are eliminated in consolidation. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.

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

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

Segment Reporting

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

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

The ~~preparation~~global spread of ~~the unaudited consolidated financial statements in conformity with GAAP requires management to make estimates~~coronavirus (“COVID-19”) created significant volatility, uncertainty, and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic ~~and commodity price environment. While management believes that the estimates and assumptions used~~disruption beginning in the ~~preparation~~first three months of 2020. On March 11, 2020, the ~~financial statements are appropriate, actual results could differ from these estimates. Significant estimates made~~World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide.

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The pandemic reached more than 200 countries and resulted in ~~preparing these financial statements include~~widespread adverse impacts on the ~~estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities and~~global economy, the ~~estimates of proved~~Partnership’s oil, natural gas, and NGL ~~reserves~~operators and ~~related present value estimates of future net cash flows from those properties.~~

~~The discounted present value of~~other parties with whom the ~~proved oil, natural gas and NGL reserves is~~Partnership has business relations, including a major component of the ceiling test calculation and requires subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information.

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant ~~revisions will not be necessary~~reduction in the future. Significant downward revisions could result in a ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

~~Reclassification of Prior Period Presentation~~

~~Certain prior period amounts have been reclassified~~global demand for ~~consistency with the current period presentation.~~

~~Cash and Cash Equivalents~~

~~The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.~~

~~Accounts Receivable~~

Oil, natural gas and NGL receivables consist of revenue amounts due to the Partnership from its mineral and royalty interests. The Predecessor’s other current assets include amounts due as reimbursement for costs incurred by the Predecessor. Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. The Partnership estimates and records an allowance for doubtful accounts when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of September 30, 2017 and December 31, 2016, no allowance for doubtful accounts is deemed necessary based upon a review of current receivables and the lack of historical write offs.

~~Property and Equipment~~

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

~~line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.~~

~~Oil and Natural Gas Properties~~

~~The Partnership follows the full-cost method of accounting for costs related to its~~ oil and natural gas ~~properties. Under this method, all such costs are capitalized~~during the 2020 period. The significant decline in demand accelerated following the announcement of price reductions and ~~amortized on an aggregate basis over the estimated lives~~production increases in March 2020 by members of the ~~properties using the unit-of-production method.~~

Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries, raising concerns about global storage capacity. The ~~capitalized costs are subject~~resulting supply and demand imbalance led to a ~~ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved~~significantly weaker outlook for oil ~~natural~~and gas ~~and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties.~~ producers in 2020.

The Partnership has ~~not assigned any value~~modified certain business practices (including those related to ~~unproved properties~~employee travel, employee work locations, and cancellation of physical participation in ~~which it holds an interest. The full-cost ceiling is evaluated at~~meetings, events and conferences) to conform to government restrictions and best practices encouraged by the ~~end~~Centers for Disease Control and Prevention (the “CDC”), the WHO and other governmental and regulatory authorities. In mid-March 2020, the Partnership restricted access to its offices to only essential employees, and directed the remainder of ~~each period and additionally when events indicate possible impairment.~~

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12‑month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices.

The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. The fair value of these acquired assets was based on the common units issuedits employees to work from home to the ~~Contributing Parties, other than~~extent possible. Beginning in mid-May 2020, the ~~Predecessor, multiplied by~~Partnership opened its offices to employees on a voluntary basis, with employees having the ~~IPO price per common unit plus the net proceeds of the IPO that were distributed~~option to the Contributing Parties, excluding the value of any common units or net proceeds distributed to the Predecessor. In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined the fair value of the acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemptionwork from the ~~SEC to exclude the properties acquired at the closing of the IPO~~office or from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that we are required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of September 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, the Partnership considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO, and management affirmed that there has not been a material change to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at September 30, 2017 of $240.8 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $78.4 million for the period ending September 30, 2017.home. The Partnership will continue to ~~assess~~give employees the ~~fair value~~option to work from the office or from home until the CDC recommends businesses and employers resume to pre-pandemic operations. 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 ~~acquired assets at each periodic reporting date to ensure inclusion~~number of employees in the ~~ceiling calculation is not required through~~office.

The ultimate impacts of COVID-19 and the ~~December 31, 2017 reporting period, which is~~volatility in the period of the exemption extended by the SEC. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired. All of the Partnership’s oil and natural gas ~~properties are subject~~markets on the Partnership’s business, cash flows, liquidity, financial condition and results of operations remain dependent on a number of factors, including, among others, the ultimate severity of COVID-19, the consequences of governmental and other measures designed to prevent the ~~full-cost ceiling test. No impairment expense was recorded for~~spread of COVID-19, the ~~period from February 8, 2017~~development, availability and administration of effective treatments and vaccines, the duration of the pandemic, 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 of any return to normal economic and operating conditions.

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 2020 Form 10-K, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the three and nine months ended September 30, ~~2017.~~2021, other than those discussed below in Recently Adopted Accounting Pronouncements.

~~No impairment expense was recorded by~~Recently Adopted Accounting Pronouncements

In December 2019, the ~~Predecessor~~Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for ~~the period from~~Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The Partnership adopted this update on January 1, ~~2017 to February 7, 2017 (the “Predecessor 2017 Period”).~~2021 and applied it prospectively. The ~~Predecessor recorded~~adoption of this update did not have a ~~full-cost ceiling impairment~~material impact on the Partnership’s results of ~~$0.3 million and $5.0 million~~

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

operations for the three and nine months ended September 30, ~~2016, respectively,~~2021.

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NOTE 3—ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY

Acquisitions

On March 10, 2021, the Partnership completed the acquisition of certain mineral and royalty assets held by Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP for a total purchase price of $0.5 million. The assets acquired were managed by Nail Bay Royalties and Duncan Management, LLC (“Duncan Management”). See Note 13—Related Party Transactions, for further discussion of the Partnership’s relation to each entity.

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, (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.

Joint Venture

On June 19, 2019, the Partnership entered into 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 $10.0 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 utilizes the equity method of accounting for its investment in the Joint Venture. As of September 30, 2021, the Partnership had paid approximately $5.1 million under its capital commitment.

Special Purpose Acquisition Company

On July 29, 2021, Kimbell Tiger Acquisition Corporation (“TGR”), the Partnership’s newly formed special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the SEC. While TGR’s initial public offering has not been consummated, the proposed public offering is expected to have a base offering size of $200.0 million, or up to $230.0 million if the underwriter’s over-allotment is exercised in full. Certain members of the Partnership’s management and members of the Board of Directors are members of the sponsor of TGR. As of September 30, 2021, we have incurred $0.3 million in deferred offering costs related to the proposed offering, which is included in other current assets in our unaudited interim condensed consolidated balance sheets.

NOTE 4—DERIVATIVES

Commodity 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, 2021, 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 production based on the amount of debt and/or preferred equity as a ~~result~~percent of ~~reductions in estimated proved reserves~~its enterprise value. As of September 30, 2021, these economic hedges constituted approximately 33% of daily oil and ~~commodity prices.~~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 ~~properties~~fixed price swap transactions are ~~depleted on~~settled based upon the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change.

Proceeds from other dispositions of oil and natural gas properties are credited to the full-cost pool. No gains or losses were recorded for the period from February 8, 2017 to September 30, 2017, the Predecessor 2017 Period, or the nine months ended September 30, 2016.

Due to the nature of the Partnership’s and the Predecessor’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the period from February 8, 2017 to September 30, 2017, the Predecessor 2017 Period, or the nine months ended September 30, 2016.

~~Other Current Liabilities~~

~~Other current liabilities consists of employee bonus accrual, ad valorem taxes and revenue processing fees.~~

~~Asset Retirement Obligations~~

Prior to the transactions that were completed in connection with the closing of the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. The Predecessor’s ARO reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Predecessor’s non-operated working interests in oil and natural gas properties.

Fair values of legal obligations to retire and remove long-lived assets were recorded when the obligation was incurred. When the liability was initially recorded, the Predecessor capitalized this cost by increasing the carrying amount of the related property and equipment. Over time, the liability was accreted for the change in its present value and the capitalized cost in oil and natural gas properties was depleted based on units of production consistent with the related asset.

~~Other Long-Term Liabilities~~

The Predecessor’s other long-term liabilities consist of a tenant improvement allowance granted at the effective date of the lease for the Partnership’s office space. This allowance was accounted for as a deferred incentive and was being amortized over the term of the lease as a reduction to rent expense. The deferred incentive was fully realized through the transactions that were completed in connection with the closing of the Partnership’s IPO and is not recognized in the Partnership’s financial statements.

~~Income Taxes~~

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

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

Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership and the Predecessor had no uncertain tax positions at September 30, 2017 and December 31, 2016, respectively.

last day settlement

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~~KIMBELL ROYALTY PARTNERS, LP~~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. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the current period and are presented on a net basis within revenue in the accompanying unaudited interim condensed consolidated statements of operations.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~Interest Rate Swaps

~~(Unaudited)~~

On January 27, 2021, the Partnership entered into an interest rate swap with Citibank, N.A., New York (“Citibank”), which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility (which represented approximately 78% of our outstanding balance as of September 30, 2021), at approximately 3.9% for the period ending on January 29, 2024. The Partnership uses an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps are recognized as gains or losses in the current period and are presented on a net basis within other income in the ~~Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to~~accompanying unaudited interim condensed consolidated statements of operations. As of September 30, ~~2017,~~2021, the ~~Predecessor 2017 Period,~~interest rate swap had a total notional amount of $150.0 million and ~~the nine months ended September 30, 2016, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions.~~a fair value of $0.5 million.

The Partnership has ~~filed all tax returns to date that are currently due. Tax years after December 31, 2013 remain subject to possible examination by taxing authorities although no such examination has been requested.~~not designated any of its derivative contracts as hedges for accounting purposes. Changes in fair value consisted of the following:

~~Concentration of Credit Risk~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Beginning fair value of derivative instruments	$	(29,998,417)	$	2,881,223	$	(6,280,863)	$	804,501
(Loss) gain on derivative instruments		(17,676,825)		(5,897,646)		(45,615,784)		193,995
Net cash paid (received) on settlements of derivative instruments		6,425,055		(675,452)		10,646,460		(4,690,371)
Ending fair value of derivative instruments	$	(41,250,187)	$	(3,691,875)	$	(41,250,187)	$	(3,691,875)

The ~~Partnership has no involvement or operational control over~~following table presents the ~~volumes and method~~fair value of ~~sale of oil, natural gas and NGL produced and sold from its properties. It is believed that~~ the ~~loss of any single purchaser would not have a material adverse effect on~~Partnership’s derivative contracts for the ~~results of operations.~~periods indicated:

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


		September 30,		December 31,
Classification	Balance Sheet Location	2021		2020
Assets:
Long-term assets	Derivative assets	$	661,338	$	—
Liabilities:
Current liabilities	Derivative liabilities		(33,731,319)		(3,113,178)
Long-term liabilities	Derivative liabilities		(8,180,206)		(3,167,685)
		$	(41,250,187)	$	(6,280,863)

~~Revenue Recognition~~

The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

As ~~an owner~~ of ~~mineral and royalty interests,~~September 30, 2021, the ~~Partnership is entitled to a portion~~Partnership’s open commodity derivative contracts consisted of the ~~revenues received from the production~~following:

Oil Price Swaps


	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High
September 2021 - December 2021	178,974	$	44.30	$	36.23	$	53.23
January 2022 - December 2022	500,552	$	41.86	$	35.65	$	46.00
January 2023 - September 2023	235,423	$	58.29	$	53.38	$	61.70

Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
October 2021 - December 2021	1,735,672	$	2.49	$	2.41	$	2.58
January 2022 - December 2022	6,357,449	$	2.46	$	2.23	$	2.70
January 2023 - September 2023	3,250,367	$	2.78	$	2.52	$	3.09

Table of oil, natural gas and associated NGLs from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and NGL sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGL produced and sold from the properties.Contents

To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within oil, natural gas and NGL receivables in the accompanying unaudited consolidated balance sheets. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.

~~Fair Value Measurements~~NOTE 5—FAIR VALUE MEASUREMENTS

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and ~~cash equivalents,~~NGL receivables, accounts receivable ~~accounts payable,~~ and other current assets and current and long-term liabilities ~~as reflected~~included in the ~~accompanying~~ unaudited interim condensed consolidated balance sheets ~~approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents~~approximated fair value as ~~the~~of September 30, 2021 and December 31, 2020 due to their short-term duration and variable interest rates that approximate ~~current market rates. These estimated fair values may not be representative~~prevailing interest rates as of ~~actual values of the~~each reporting period. As a result, these financial ~~instruments that could have been realized or that will be realized in the future.~~

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

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

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

●

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

●

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

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

●

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

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

~~Recently Issued Accounting Pronouncements~~

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

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

In June 2016, the FASB issued ASU 2016‑13, “Measurement of Credit Losses on Financial Instruments.” ASU 2016‑13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earningshierarchy levels as of the ~~beginning~~end of the ~~first~~ reporting period in which the ~~guidance is adopted.~~event or change in circumstances causing the transfer occurred. The Partnership ~~does~~did not ~~believe this standard will~~ have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and nine months ended September 30, 2021 and 2020.

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

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

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


	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total
September 30, 2021
Assets
Interest rate swap contracts	$	—	$	661,338	$	—	$	—	$	661,338
Liabilities
Commodity derivative contracts	$	—	$	(41,701,421)	$	—	$	—	$	(41,701,421)
Interest rate swap contracts	$	—	$	(210,104)	$	—	$	—	$	(210,104)
December 31, 2020
Liabilities
Commodity derivative contracts	$	—	$	(6,280,863)	$	—	$	—	$	(6,280,863)

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~~KIMBELL ROYALTY PARTNERS, LP~~NOTE 6—OIL AND NATURAL GAS PROPERTIES

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

~~(Unaudited)~~

~~In March 2016, the FASB issued ASU 2016‑09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016‑09 simplifies several aspects~~Oil and natural gas properties consist of the ~~accounting~~following:


	September 30,		December 31,
	2021		2020
Oil and natural gas properties
Proved properties	$	977,763,680	$	923,413,606
Unevaluated properties		171,847,133		225,681,626
Less: accumulated depreciation, depletion and impairment		(652,252,233)		(628,102,279)
Total oil and natural gas properties	$	497,358,580	$	520,992,953

The Partnership assesses all unevaluated properties on a periodic basis for ~~share-based payment transactions, including accounting for income taxes, forfeitures~~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 ~~statutory tax withholding requirements,~~market conditions, operators’ intent to drill, remaining lease term, geological and geophysical evaluations, operators’ drilling results and activity, the assignment of proved reserves and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as ~~well as certain classification changes~~to the existence of proved reserves is able to be made. 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 ~~statement~~first quarter of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Partnership adopted this standard effective at the issuance of its restricted units under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) on May 12, 2017. The Partnership elected to account for forfeitures as they occur2020 as a result of ~~adopting~~ this ~~standard.~~

In March 2016, the FASB issued ASU 2016-08, “Revenue from Contracts with Customers—Principal versus Agent Considerations (Reporting Revenue Gross versus Net).” Under this update, an entity should recognize revenue to depict theimpairment assessment. The transfer ~~of promised goods or services to customers~~resulted in an additional ceiling test impairment expense for the first quarter of 2020 equal to the amount ~~that reflects~~of the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, and early application is not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presentedtransfer.

After evaluating certain external factors in the ~~financial statements, or modified retrospective adoption, meaning this update is applied only~~first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated proved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the ~~most current period presented.~~Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties in the first quarter of 2020. The Partnership ~~is still evaluating the impact~~did not book PUD reserves in its total estimated proved reserves as of ~~this standard, however,~~September 30, 2021 or December 31, 2020 and it does not ~~expect that there will~~intend to book PUD reserves going forward.

The Partnership did 0t record an impairment on its oil and natural gas properties for the three and nine months ended September 30, 2021. The Partnership recorded an impairment on its oil and natural gas properties of $22.2 million and $158.7 million for the three and nine months ended September 30, 2020, respectively, which can primarily be ~~a significant change in the manner~~attributed to factors mentioned above.

NOTE 7—LEASES

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

~~In February 2016,~~Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the ~~FASB issued ASU 2016‑02, “Leases.” ASU 2016‑02 requires the recognition of~~lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying unaudited interim 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, 2021 is 7.59 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by ~~lessees~~the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term,

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an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for ~~those leases currently~~the operating lease was 6.75% for the nine months ended September 30, 2021.

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 interim condensed consolidated statements of operations for the three and nine months ended September 30, 2021 and 2020. The total operating lease expense recorded for both the three months ended September 30, 2021 and 2020 was $0.1 million. The total operating lease expense recorded for both the nine months ended September 30, 2021 and 2020 was $0.4 million.

Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases ~~and makes certain changes to~~are the ~~way~~main office spaces used for operations.

Future minimum lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases.

In May 2014, the FASB issued ASU 2014-09, “Revenue From Contracts with Customers (Topic 606).” an ASU on a comprehensive new revenue recognition standard that will supersede ASC 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-upcommitments as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-upSeptember 30, 2021 were as ~~of the current period.~~follows:

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


	Total		2021		2022		2023		2024		2025		Thereafter
Operating leases	$	3,807,914	$	121,409	$	486,045	$	487,787	$	488,725	$	497,033	$	1,726,915
Less: Imputed Interest		(872,141)
Total	$	2,935,773

NOTE ~~3—ACQUISITIONS~~

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

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

~~NOTE 4—~~8—LONG-TERM DEBT

~~In connection with its IPO,~~On January 11, 2017, the Partnership entered into a ~~$50.0 million~~credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018, the Partnership entered into an amendment (the “First Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement (the 2017 Credit Agreement as amended by the First Credit Agreement Amendment, the “2018 Amended Credit Agreement”).

On December 8, 2020, the Partnership entered into Amendment No. 2 (the “Second Credit Agreement Amendment”) to the 2018 Amended Credit Agreement (the 2018 Amended Credit Agreement as amended by the Second Credit Agreement Amendment, the “Amended Credit Agreement”).

The Second Credit Agreement Amendment amends the 2018 Amended Credit Agreement to, among other things, (i) increase commitments under the Amended Credit Agreement’s senior secured revolving credit facility ~~that is secured by substantially all~~from $225.0 million to $265.0 million, the availability of ~~its assets and the assets of its wholly owned subsidiaries. Availability under the secured revolving credit facility equals~~which will equal the lesser of the aggregate maximum elected commitments of the lenders up to $500.0 million, subject to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders, and the borrowing ~~base.~~base, (ii) extend the maturity date under the 2018 Amended Credit Agreement from February 8, 2022 to June 7, 2024, (iii) reflect the change in administrative agent from Frost to with Citibank, N.A., New York (“Citibank”) under the Amended Credit Agreement, (iv) increase the applicable margin under the 2018 Amended Credit Agreement, which varies based upon the level of borrowing base usage, by 1.00% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 2.00% to 3.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 3.00% to 4.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement), (v) provide for a LIBOR (as defined in the Amended Credit Agreement) floor of 0.25%, (vi) modify the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) financial covenant to permit the numerator of the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) to be calculated as Total Debt (as defined in the Amended Credit Agreement) minus up to $25 million in unrestricted cash held by the Partnership and its restricted subsidiaries and to decreases the maximum permitted Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) from 4.0 to 1.0 to 3.5 to 1.0, and (vii) modify the conditions permitting restricted distributions to holders of Kimbell Common Units (as defined in the Amended Credit Agreement) including, among other things, a limitation on such distributions to not be in excess of the Partnership’s Projected Cash Available For Distribution (as defined in the Amended Credit Agreement). In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be ~~re-determined~~redetermined semi-annually on ~~February~~or about May 1 and ~~August~~November 1 of each year, beginning May 1, 2021, based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the ~~its~~Partnership’s wholly owned subsidiaries. In connection with the ~~August~~May 1, 2021 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at ~~$100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0~~$265.0 million. The ~~secured revolving credit facility permits aggregate commitments~~November borrowing base redetermination is currently being conducted and is expected to be ~~increased to $100.0 million, subject to~~finalized by the ~~satisfaction~~end of ~~certain conditions and the procurement~~November 2021.

Table of ~~additional commitments from new or existing lenders. The secured revolving credit facility matures on February 8, 2022.~~Contents

The ~~secured revolving credit facility~~Amended Credit Agreement 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 and OpCo 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~~Amended Credit Agreement 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)~~Amended Credit Agreement) of not more than ~~4.0~~3.5 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~~Amended Credit Agreement also contains customary events of default, including ~~non‑payment,~~non-payment, breach of covenants, materially incorrect representations, ~~cross‑~~cross default, bankruptcy and change of control.

During the nine months ended September 30, 2021, the Partnership borrowed an additional $40.6 million under the secured revolving credit facility and repaid approximately $19.4 million of the outstanding borrowings. As of September 30, ~~2017,~~2021, the Partnership’s outstanding balance was ~~$22.2~~$192.7 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of September 30, ~~2017.~~2021.

~~During the period ended~~As of September 30, ~~2017,~~2021, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of ~~2.25% and Prime Rate~~3.50% or the ABR (as defined in the ~~secured revolving credit facility)~~Amended Credit Agreement) plus a margin of ~~1.25%~~2.50%. For the ~~period from February 8, 2017 to~~three and nine months ended September 30, ~~2017,~~2021, the weighted average interest rate on the Partnership’s outstanding borrowings was ~~3.51%.~~3.99% and 3.84%, respectively.

OnNOTE 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 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 on the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units. In May 2021, the Series A Purchasers and the Partnership agreed to waive the board observer rights, that were set to begin in July 2021, until January ~~31, 2014,~~2022.

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

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

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

On February ~~8, 2017,~~12, 2020, the Partnership completed ~~its IPO~~the redemption of ~~5,750,000 common~~55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than 50% of the carrying value of the Series A preferred units as of the redemption date and 50% of the original intrinsic value of the beneficial conversion feature, a deemed

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dividend distribution of $5.7 million was recognized in unitholders’ equity and non-controlling interest during the nine months ended September 30, 2020.

On July 7, 2021, the Partnership completed the redemption of 30,000 Series A preferred units, representing 55% of the then-outstanding Series A preferred units, with 25,000 Series A preferred units still outstanding. The Series A preferred units were redeemed at a price of $1,202.51 per Series A preferred unit for an aggregate redemption price of $36.1 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 $3.8 million was recognized in unitholders’ equity and non-controlling interest during the three and nine months ended September 30, 2021.

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


		Series A
		Preferred Units
Balance at December 31, 2020		55,000
Redemption of Series A preferred units		(30,000)
Balance at September 30, 2021		25,000

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner ~~interests, which included~~interests. As of September 30, 2021, the Partnership had a total of 42,916,472 common units issued and outstanding and 17,611,579 Class B units outstanding.

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

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


		Common Units
Balance at December 31, 2020		38,918,689
Conversion of Class B units		3,168,202
Common units issued under the LTIP (1)		936,567
Restricted units repurchased for tax withholding		(106,986)
Balance at September 30, 2021		42,916,472

(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 25, 2021.

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

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


	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2021	$	0.27	April 23, 2021	May 3, 2021	May 10, 2021
Q2 2021	$	0.31	July 23, 2021	August 2, 2021	August 9, 2021
Q3 2021	$	0.37	October 22, 2021	November 1, 2021	November 8, 2021

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

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


		Class B Units
Balance at December 31, 2020		20,779,781
Conversion of Class B units		(3,168,202)
Balance at September 30, 2021		17,611,579

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

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

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

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

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

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

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

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

common unit:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net income (loss) attributable to common units	$	1,837,579	$	(17,795,643)	$	2,624,532	$	(105,125,328)

Weighted average number of common units outstanding:
Basic		41,106,157		35,423,112		39,383,172		33,540,977
Effect of dilutive securities:
Series A preferred units		—		—		—		—
Class B units		—		—		—		—
Restricted units		1,513,315		—		1,729,652		—
Diluted		42,619,472		35,423,112		41,112,824		33,540,977

Net income (loss) attributable to common units
Basic	$	0.04	$	(0.50)	$	0.07	$	(3.13)
Diluted	$	0.04	$	(0.50)	$	0.06	$	(3.13)

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.

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NOTE 7—12—UNIT-BASED COMPENSATION

The Partnership’s LTIP authorizes grants of up to ~~2,041,600~~4,541,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued under ~~our~~the Partnership’s LTIP generally vest in ~~one-third~~ one-thirdinstallments 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 ~~will be accrued for services provided during~~is treated in the ~~intervening periods between~~same manner as that of the ~~grant~~employees and ~~vesting dates, utilizing then-current fair values for the awards and applying mark-to-market accounting until actual vesting occurs.~~

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

directors.

Distributions related to the restricted units are paid concurrently with ~~our~~the Partnership’s distributions for common units. The fair value of ~~our~~the Partnership’s restricted units issued under ~~our~~the LTIP to ~~our~~the Partnership’s employees, directors and ~~directors~~consultants is determined by utilizing the market value of ~~our~~the Partnership’s common units on the respective grant date. ~~The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs.~~ The following table presents a summary of the Partnership’s unvested ~~common~~restricted units.

Weighted

Weighted

Weighted

Average

Average

Average

Grant-Date

Market-Date

Remaining

Fair Value

Fair Value

Contractual

Units

per Unit

per Unit

Term
Unvested at February 8, 2017

—

$
—

$
—

—
Granted - service condition employees

143,318

18.655

—

—
Granted - service condition consultants

24,253

—

15.780

—
Granted - non-employee directors

9,520

15.780

Vested

(9,520)

—

—

—
Forfeited

—

—

—

—
Exercised

—

—

—

—
Unvested at September 30, 2017

167,571

$
18.655

$
15.780

1.616 years


		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2020	1,276,546	$	13.604	1.788 years
Awarded	936,567		10.350	—
Vested	(419,535)		13.460	—
Unvested at September 30, 2021	1,793,578	$	11.938	1.789 years

Prior to the IPO, the Predecessor had a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options as compensation for services performed for the Predecessor. The options carried a distribution right, whereby the option holder received distributions that were commensurate with those given to holders of membership units.

~~A summary of the option activity as of February 7, 2017 is as follows:~~

Weighted

Weighted

Average

Average

Remaining

Exercise

Contractual

Units

Price

Term
Outstanding, December 31, 2016 - Predecessor

110,000

$
100

8.00 years
Granted

—

—

—
Forfeited

—

—

—
Exercised

—

—

—
Outstanding, February 7, 2017

110,000

$
100

7.92 years
Exercisable, February 7, 2017

—

$
—

—

For the Predecessor 2017 Period and the nine months ended September 30, 2016, total compensation expense for awards under the Predecessor’s long-term incentive plan was $50,422 and $453,795, respectively, and is included general and administrative expenses in the accompanying unaudited consolidated statements of operations. In connection with the transactions that were completed at the closing of the Partnership’s IPO, the outstanding options to purchase membership units under the Predecessor’s long-term incentive plan expired and were not converted to units in the Partnership.

NOTE ~~8—ASSET RETIREMENT OBLIGATIONS~~

Prior to the transactions that were completed in connection with the IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. As of the closing of its IPO and through the date of this Quarterly Report, the Partnership did not own any working interests and did not have any ARO or any lease operating expenses as a working interest owner.

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

~~NOTE 9—~~13—RELATED PARTY TRANSACTIONS

~~In connection with the IPO, the~~The Partnership ~~entered into~~currently has a management services agreement with Kimbell Operating, which ~~entered into~~has separate ~~service~~services agreements with ~~Steward~~each of BJF Royalties, LLC (“~~Steward~~BJF Royalties”~~), Taylor Companies Mineral Management, LLC (“Taylor Companies”~~), 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 ~~service~~services agreements, affiliates of the Partnership’s Sponsors ~~will~~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 ~~service~~services agreements will reduce the amount of cash available for distribution on common units to the Partnership’s unitholders.

On March 10, 2021, the Partnership acquired certain assets managed by Nail Bay Royalties and Duncan Management. See Note 3—Acquisitions and Joint Ventures for further detail.

During the three and nine months ended September 30, 2021, 0 monthly services fee was paid to BJF Royalties. During the three months ended September 30, ~~2017,~~2021, the Partnership made payments to ~~Steward Royalties, Taylor Companies,~~ K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of ~~$100,000, $100,000,~~ $30,000, ~~$125,884~~$75,329 and ~~$164,616,~~$137,120, respectively. During the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017,~~2021, the Partnership made payments to ~~Steward Royalties, Taylor Companies,~~ K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of ~~$266,667, $266,667, $80,000, $335,691~~$90,000, $225,986 and ~~$438,975,~~$411,360, respectively. Certain consultants who provide services under ~~the above mentioned~~ management services agreements ~~were~~are granted restricted units under the Partnership’s ~~LTIP on May 12, 2017.~~LTIP.

NOTE 14—COMMITMENTS AND CONTINGENCIES

During the ~~Predecessor 2017 Period and~~normal course of business, the ~~nine months ended September 30, 2016,~~Partnership may experience situations where disagreements occur relating to the ~~Predecessor Company’s activities included~~ownership of certain ~~related party receivables and payables; however, such amounts were de minimis at December 31, 2016.~~

~~NOTE 10—ADMINISTRATIVE SERVICES~~

The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business efforts. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the Board of Directors and their affiliated entities. See Note 9―Related Party Transactions.

~~NOTE 11—COMMITMENTS AND CONTINGENCIES~~

mineral or overriding royalty interest acreage. Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or ~~liquidity.~~liquidity as of September 30, 2021.

NOTE ~~12—~~15—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to September 30, ~~2017~~2021 in the preparation of its unaudited interim condensed consolidated financial statements.

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Debt

On October ~~27, 2017,~~28, 2021 the Partnership drew down $8.0 million on the senior secured revolving credit facility to fund certain operational expenses.

Distributions

On November 2, 2021, the Partnership paid a quarterly cash distribution on the Series A preferred units of approximately $0.4 million for the quarter ended September 30, 2021.

On November 2, 2021, 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 $17,612 for the quarter ended September 30, 2021.

On October 22, 2021, the Board of Directors declared a quarterly cash distribution of ~~$0.31~~$0.37 per common unit for the quarter ended September 30, ~~2017.~~2021. The distribution will be paid on November ~~13, 2017~~8, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on November ~~6, 2017.~~

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

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

1, 2021.

1517

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

The following discussion and analysis of financial ~~condition~~condition and results of operations should be read together in conjunction with our unaudited interim condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form ~~10‑Q~~10-Q (this “Quarterly Report”), as well as ~~the historical~~our audited financial statements ~~of our accounting predecessor for accounting~~ and ~~financial reporting purposes, Rivercrest Royalties, LLC, (“Rivercrest” or the “Predecessor”)~~notes thereto included in our Annual Report on Form ~~10‑K~~10-K for the year ended December 31, ~~2016.~~2020 (the “2020 Form 10-K”).

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

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

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

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

●

our ability to replace our reserves;

●

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

●

our ability to execute our business strategies;

●

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

liquids (“NGLs”), including as a result of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries;

●

the level of production on our properties;

●

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

●

our ability to forecast identified drilling locations, gross horizontal wells, drilling inventory and estimates of reserves on our properties and on properties we seek to acquire;

●

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

●

~~our ability to replace our reserves;~~

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

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

political conditions, including the energy and environmental proposals supported by the Biden administration and/or the United States Congress, 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;

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●

impacts of impairment expense on our financial statements;

●

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

industry generally and the mineral and royalty industry in particular;

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●

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

●

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

acquire an interest;

●

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

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;~~

industry, including the Biden administration’s proposals and recent executive orders focused on addressing climate change;

●

future operating results;

●

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

●

operating hazards faced by the operators of our properties;

●

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

●

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

uncertainties regarding United States federal income tax law, including the treatment of our future earnings and distributions;

●

the possibility that we may not be able to consummate the initial public offering of Kimbell Tiger Acquisition Corporation (“TGR”) on the expected timeline or at all, that we may not find a suitable business combination within the prescribed time period, that the business combination may not be successful or that the activities for TGR could be distracting to our management; and

●

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

~~All forward‑looking~~These factors are discussed in further detail in the 2020 Form 10-K 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 elsewhere in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are ~~expressly qualified in their entirety by the foregoing cautionary statements.~~made, whether as a result of new information, future events or otherwise.

Overview

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

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As of September 30, ~~2017,~~2021, we owned mineral and royalty interests in approximately ~~3.7~~9.1 million gross acres and overriding royalty interests in approximately ~~2.0~~4.6 million gross acres, with approximately ~~35%~~60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. We refer to these ~~non‑cost‑bearing~~non-cost-bearing interests collectively as our “mineral and royalty interests.” As of September 30, ~~2017,~~2021, over ~~95%~~98% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 2028 states and in ~~nearly~~ every major onshore basin across the continental United States and include ownership in over ~~50,000~~97,000 gross ~~producing~~ wells, including over ~~29,000~~41,000 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, 2021:


			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	2,662,777	23,075	2,474	1,939	41,075
Mid‑Continent	3,955,148	41,402	1,603	968	11,267
Haynesville	786,724	7,665	3,850	1,318	8,861
Appalachia	741,354	23,202	1,996	836	3,208
Bakken	1,569,637	6,051	867	732	4,124
Eagle Ford	624,148	6,730	1,793	1,401	3,235
Rockies	74,152	1,036	974	576	12,359
Other	3,232,561	36,694	1,253	705	13,028
Total	13,646,501	145,855	14,810	8,475	97,157

(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 2020 Form 10-K.

(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, 2021:


Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	328	270	0.56	0.82
Mid‑Continent	96	58	0.19	0.10
Haynesville	86	25	0.33	0.30
Appalachia	12	38	0.03	0.13
Bakken	153	166	0.22	0.72
Eagle Ford	74	74	0.32	0.66
Rockies	21	43	0.04	0.29
Total	770	674	1.69	3.02

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(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

InPartial Redemption of Series A Preferred Units

On July 7, 2021, we completed the ~~second quarter~~redemption of ~~2017,~~30,000 Series A preferred units, representing 55% of the ~~Partnership acquired mineral and royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres,~~then-outstanding Series A preferred units, with 25,000 Series A preferred units still outstanding. The Series A preferred units were redeemed at a price of $1,202.51 per Series A preferred unit for an aggregate ~~purchase~~redemption price of ~~approximately $16.8~~$36.1 million. ~~The Partnership funded these acquisitions with borrowings under its~~

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Debt

On July 1, 2021 we drew down $36.1 million on the senior secured revolving credit ~~facility.~~facility to fund the redemption of the Series A preferred units.

On October ~~9, 2017,~~28, 2021 we drew down $8.0 million on the Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded these acquisitions with borrowings under itssenior secured revolving credit ~~facility. The Partnership was required~~facility to ~~put down~~fund certain operational expenses.

Special Purpose Acquisition Company

On July 29, 2021, TGR, our newly formed special purpose acquisition company and subsidiary, filed a ~~deposit~~registration statement on Form S-1 with the U.S. Securities and Exchange Commission (the “SEC”). While TGR’s initial public offering has not been consummated, the proposed public offering is expected to have a base offering size of $200.0 million, or up to $230.0 million if the underwriter’s over-allotment is exercised in full. Certain members of our management and members of the General Partner’s Board of Directors (the “Board of Directors”) are members of the sponsor of TGR. Determinations with respect to TGR’s proposed initial public offering will be subject to market conditions and other factors. This Quarterly Report is not an offer to purchase or a solicitation of an offer to buy any securities of TGR, nor will there be any sale of securities in any jurisdiction in which such offer or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. As of September 30, 2021, we incurred $0.3 million in deferred offering costs related to the proposed offering, which is included in ~~deposits~~other current assets in our unaudited interim condensed consolidated balance sheets.

Quarterly Distributions

On November 2, 2021, we paid a quarterly cash distribution on the Series A preferred units of approximately $0.4 million for the quarter ended September 30, 2021.

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 units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution. On November 2, 2021, we paid a quarterly cash distribution to each Class B unitholder, resulting in a total quarterly distribution of $17,612 for the quarter ended September 30, 2021.

On October 22, 2021, Board of Directors declared a quarterly cash distribution of $0.37 per common unit for the quarter ended September 30, 2021. The distribution will be paid on November 8, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on November 1, 2021.

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 2020 and continuing into early 2021. 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 reached more than 200 countries and 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 ~~properties~~during the 2020 period. The 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 led to a significantly weaker outlook for oil and gas producers and had a disruptive impact on the oil and natural gas industry. Globally, these conditions led to significant economic contraction during the 2020 period.

Our first priority in our response to this crisis has been and will continue to be 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 physical participation in meetings, events and conferences) to conform to government restrictions and best

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practices encouraged by the Centers for Disease Control and Prevention (the “CDC”), the WHO and other governmental and regulatory authorities. In mid-March 2020, 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 2020 we opened our offices to employees on a voluntary basis, with employees having the option to work from home. We will continue to give employees the option to work from home until the CDC recommends businesses and employers resume to pre-pandemic operations. 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 ~~accompanying unaudited consolidated balance sheet at~~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 COVID-19, 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 second half of 2020 and through 2021, the possibility of future restrictions remains. 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 was met with a sharp decline in oil prices which were exacerbated by the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries. The resulting supply and demand imbalance had disruptive impacts on the oil and natural gas exploration and production industry and on other related industries in 2020. These industry conditions, coupled with those resulting from the COVID-19 pandemic, 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 substantially increased for the 2020 period as a result of COVID-19, the OPEC announcements mentioned above and ongoing storage capacity concerns. While oil prices declined sharply in April 2020, both pricing and activity began to improve, with oil prices rising above pre-COVID-19 levels in the first half of 2021. Although strip pricing for natural gas has increased meaningfully, the impact of these developments on our business and the oil and gas industry is unpredictable. We derived approximately 37% of our revenues and 61% of our production on a Boe/d basis (6:1) from natural gas for the nine months ended September 30, ~~2017.~~2021, which we believe presents some downside protection against depressed oil prices in the event our industry experiences a drop in oil prices similar to those experienced in 2020.

~~On November 8, 2017,~~The ultimate impacts of COVID-19 and the ~~Partnership acquired mineral~~volatility in the oil and ~~royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price~~natural gas markets on our business, cash flows, liquidity, financial condition and results of ~~approximately $7.3 million~~operations remain dependent on a number of factors, including, among others, the ultimate severity of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other third parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in ~~various counties~~Part I, Item 1A. Risk Factors in ~~Arkansas. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.~~our 2020 Form 10-K.

~~Business Environment~~

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. ~~In late 2014, prices for~~As noted above, the supply and demand imbalance resulting from the COVID-19 outbreak and various OPEC announcements, along with the winter storms experienced in parts of the United States in February 2021, have created increased volatility in oil and natural gas ~~declined precipitously, and prices remained low throughout 2015 and~~prices. The table below demonstrates such volatility for the ~~majority of 2016 until rebounding in~~periods presented as reported by the ~~fourth quarter of 2016. During~~United States Energy Information Administration (“EIA”).


	Nine Months Ended September 30, 2021				Nine Months Ended September 30, 2020
	High		Low		High		Low
Oil ($/Bbl)	$	75.54	$	47.47	$	63.27	$	(36.98)
Natural gas ($/MMBtu)	$	23.86	$	2.43	$	2.57	$	1.33

On October 29, 2021, the ~~nine months ended September 30, 2017,~~ West Texas Intermediate (“WTI”) ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $54.48 per Bbl on February 23, 2017, and during the nine months ended September 30, 2016, WTI ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $51.23 per Bbl on June 8, 2016. During the nine months ended September 30, 2017, the Henry Hub spot market price of natural gas ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017. During the nine months ended September 30, 2016, the Henry Hub spot market price of natural gas ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $3.19 per MMBtu on September 21, 2016. On October 30, 2017, the WTI posted price for crude oil was ~~$54.11~~$83.50 per Bbl and the Henry Hub spot market price of natural gas was ~~$2.94~~$5.49 per MMBtu.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Oil ($/Bbl)	$	70.58	$	40.89	$	65.05	$	38.04
Natural gas ($/MMBtu)	$	4.35	$	2.00	$	3.61	$	1.87

Rig Count

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

For the three months ended September 30,

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

2017

2016

2017

2016
Oil (Bbl)

$
48.18

$
44.85

$
49.30

$
41.35
Natural gas (MMBtu)

$
2.95

$
2.88

$
3.01

$
2.34

~~Source: EIA~~future leasing and drilling activity on our acreage.

~~Rig Count~~

The Baker Hughes ~~U.S.~~United States Rotary Rig count ~~was 940~~increased significantly to 513 active ~~rigs at September 29, 2017, an 80% increase from 522 active~~land rigs at September 30, ~~2016. In addition, according~~2021 compared to ~~the Baker Hughes U.S. Rotary Rig count, rig activity in the 20 states in which we own mineral and royalty interests increased 83% from 468~~251 active land rigs at September 30, ~~2016 to 857~~2020. The 513 active land rigs at September ~~29, 2017.~~30, 2021 increased by 11.8% from 459 active land rigs at June 30, 2021. The ~~active~~increase in rig count ~~across~~is primarily attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas prices.

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


	September 30,
Basin or Producing Region	2021	2020
Permian Basin	24	12
Mid‑Continent	10	5
Haynesville	16	8
Appalachia	—	1
Bakken	5	2
Eagle Ford	5	1
Rockies	—	1
Total	60	30

Sources of Our Revenue

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

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Royalty income
Oil sales	47	%	57	%	49	%	57	%
Natural gas sales	39	%	33	%	37	%	34	%
NGL sales	11	%	10	%	11	%	9	%
Lease bonus and other income	3	%	-	%	3	%	-	%
	100	%	100	%	100	%	100	%

We have entered into ~~hedging arrangements~~oil and natural gas commodity derivative agreements, which extend through September 2023, to establish, in advance, a price for the sale of a portion of the oil and natural gas ~~and NGLs~~ produced from our mineral and royalty interests. ~~As a result, we may realize the benefit~~

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

Non-GAAP Financial Measures

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

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

~~Adjusted EBITDA~~

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

We define Adjusted EBITDA as net income (loss) ~~plus~~, net of depreciation and depletion expense, interest expense, ~~net of capitalized interest, non‑cash unit‑based compensation,~~income taxes, impairment of oil and natural gas properties, non-cash unit-based compensation, change in fair value of open derivative instruments, cash distribution from affiliate and equity income ~~taxes and depreciation, depletion and accretion expense.~~in affiliate. Adjusted EBITDA is not a measure of ~~the~~net income (loss) as determined by ~~the~~ generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution as Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

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

1924

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


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

											Three Months Ended September 30,				Nine Months Ended September 30,
											2021		2020		2021		2020
Reconciliation of net income (loss) to Adjusted EBITDA and cash available for distribution:
Net income (loss)	$	119,029	$	(769,166)	$	653,898	$	(496,856)	$	(6,018,014)	$	7,466,496	$	(25,676,624)	$	11,714,289	$	(162,251,073)
Depreciation, depletion and accretion expense		4,488,915		418,969		11,156,292		113,639		1,244,023
Depreciation and depletion expense												8,828,517		10,704,945		25,076,429		36,002,109
Interest expense		225,302		103,596		468,429		39,307		314,081		2,495,465		1,603,006		6,692,263		4,689,907
State income taxes		—		4,212		—		—		13,401
Cash distribution from affiliate												174,636		—		664,916		—
Benefit from income taxes												—		(694,864)		—		(694,864)
EBITDA		4,833,246		(242,389)		12,278,619		(343,910)		(4,446,509)		18,965,114		(14,063,537)		44,147,897		(122,253,921)
Impairment of oil and natural gas properties		—		306,959		—		—		4,992,897		—		22,237,131		—		158,698,835
Unit‑based compensation		434,197		151,265		569,889		50,422		453,795
Adjusted EBITDA	$	5,267,443	$	215,835	$	12,848,508	$	(293,488)	$	1,000,183
Unit-based compensation												2,760,528		2,446,329		8,196,939		7,088,114
Loss on derivative instruments, net of settlements												11,251,770		6,573,098		34,969,324		4,496,376
Cash distribution from affiliate												314,786		210,999		500,389		457,410
Equity income in affiliate												(261,336)		(292,803)		(719,958)		(460,360)
Consolidated Adjusted EBITDA												33,030,862		17,111,217		87,094,591		48,026,454
Adjusted EBITDA attributable to noncontrolling interest												(9,610,844)		(5,953,129)		(26,699,083)		(17,700,368)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP												23,420,018		11,158,088		60,395,508		30,326,086
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		166,707		219,900		276,246		34,505		280,010		1,426,409		902,448		3,774,193		2,474,715
Capital expenditures		—		—		—		—		—
Cash available for distribution	$	5,100,736	$	(4,065)	$	12,572,262	$	(327,993)	$	720,173
Cash distributions on Series A preferred units												310,205		627,639		1,624,835		2,419,992
Restricted units repurchased for tax withholding												—		—		763,093		—
Distributions on Class B units												17,610		23,141		59,170		71,089
Cash available for distribution on common units											$	21,665,794	$	9,604,860	$	54,174,217	$	25,360,290

Partnership

Predecessor

Partnership

Predecessor

Three Months Ended September 30,

Three Months Ended September 30,

Period from February 8, 2017 to September 30,

Period from January 1, 2017 to February 7,

Nine Months Ended September 30,

2017

2016

2017

2017

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

Net cash provided by operating activities

$
5,387,438

$
406,518

$
13,965,478

$
186,719

$
956,793
Interest expense

225,302

103,596

468,429

39,307

314,081
State income taxes

—

4,212

—

—

13,401
Impairment of oil and natural gas properties

—

(306,959)

—

—

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

(15,625)

(12,723)

(41,667)

(4,241)

(34,245)
Amortization of tenant improvement allowance

—

(32,603)

—

2,864

25,777
Unit-based compensation

(434,197)

(151,265)

(569,889)

(50,422)

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

Oil, natural gas and NGL revenues receivable

555,908

1,258,156

496,886

(14,551)

(11,258)
Other receivables

65,175

(1,246,269)

258,785

(333,056)

(1,246,269)
Accounts payable

228,080

(274,023)

(152,569)

(247,972)

1,071,453
Other current liabilities

(1,178,835)

8,971

(2,146,834)

77,442

(89,550)
EBITDA

$
4,833,246

$
(242,389)

$
12,278,619

$
(343,910)

$
(4,446,509)
Add:

Impairment of oil and natural gas properties

—

306,959

—

—

4,992,897
Unit‑based compensation

434,197

151,265

569,889

50,422

453,795
Adjusted EBITDA

$
5,267,443

$
215,835

$
12,848,508

$
(293,488)

$
1,000,183

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f
	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution:
Net cash provided by operating activities	$	25,122,540	$	12,379,324	$	69,082,654	$	47,924,350
Interest expense		2,495,465		1,603,006		6,692,263		4,689,907
Benefit from income taxes		—		(694,864)		—		(694,864)
Impairment of oil and natural gas properties		—		(22,237,131)		—		(158,698,835)
Amortization of right-of-use assets		(75,593)		(69,559)		(221,294)		(205,518)
Amortization of loan origination costs		(394,582)		(275,898)		(1,148,066)		(808,534)
Equity income in affiliate		261,336		292,803		719,958		460,360
Forfeiture of restricted units		—		12,614		—		118,859
Unit-based compensation		(2,760,528)		(2,446,329)		(8,196,939)		(7,088,114)
Loss on derivative instruments, net of settlements		(11,251,770)		(6,573,098)		(34,969,324)		(4,496,376)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		6,964,956		4,272,714		13,130,343		(3,131,377)
Accounts receivable and other current assets		(55,098)		559,160		521,569		870,069
Accounts payable		(133)		194,641		(139,753)		212,162
Other current liabilities		(1,417,494)		(1,150,481)		(1,552,405)		(1,611,232)
Operating lease liabilities		76,015		69,561		228,891		205,222
EBITDA		18,965,114		(14,063,537)		44,147,897		(122,253,921)
Add:
Impairment of oil and natural gas properties		—		22,237,131		—		158,698,835
Unit-based compensation		2,760,528		2,446,329		8,196,939		7,088,114
Loss on derivative instruments, net of settlements		11,251,770		6,573,098		34,969,324		4,496,376
Cash distribution from affiliate		314,786		210,999		500,389		457,410
Equity income in affiliate		(261,336)		(292,803)		(719,958)		(460,360)
Consolidated Adjusted EBITDA		33,030,862		17,111,217		87,094,591		48,026,454
Adjusted EBITDA attributable to noncontrolling interest		(9,610,844)		(5,953,129)		(26,699,083)		(17,700,368)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		23,420,018		11,158,088		60,395,508		30,326,086
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		1,426,409		902,448		3,774,193		2,474,715
Cash distributions on Series A preferred units		310,205		627,639		1,624,835		2,419,992
Restricted units repurchased for tax withholding		—		—		763,093		—
Distributions on Class B units		17,610		23,141		59,170		71,089
Cash available for distribution on common units	$	21,665,794	$	9,604,860	$	54,174,217	$	25,360,290

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

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

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

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

The historical financial data of our Predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the Partnership as a whole and may not provide an accurate indication of what our actual results would have been if the transactions completed in connection with our IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The mineral and royalty interests from third parties, affiliates of our ~~Predecessor only represent approximately 11%~~Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our ~~total~~Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other

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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, 2021 and 2020 include the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”).

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

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

Impairment of Oil and Natural Gas Properties

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

NoWe did not record an impairment ~~expense was recorded for the period from February 8, 2017 to September 30, 2017. The substantial majority of~~on our ~~proved~~ oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the U.S. Securities and Exchange Commission (“SEC”) to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that we are required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of September 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, we considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for ~~the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO~~

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

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

~~Credit Agreements~~

In connection with our IPO, we entered into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. As of September 30, 2017, we had borrowed $22.2 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC (“Kimbell Operating”) and the acquisition of mineral and royalty interests for an aggregate purchase price of approximately $20.7 million.2021. For ~~the three months ended September 30, 2017 and the period from February 8, 2017 to September 30, 2017, we incurred $225,302 and $468,429, respectively, in interest expense.~~

~~In January 2014, our Predecessor entered into a credit agreement with Frost Bank, as lender. For the Predecessor 2017 Period and~~ the three and nine months ended September 30, ~~2016,~~2020, we recorded an impairment on our ~~Predecessor’s interest expense was $39,307, $103,596~~oil and ~~$314,081, respectively. Our Predecessor had outstanding borrowings~~natural gas properties of ~~$10.6~~$22.2 million and $158.7 million, respectively, which 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 below.

After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic, 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, as well as longer-term commodity price outlooks, 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, ~~2016. We~~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 ~~assume any indebtedness~~have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties in the first quarter of 2020. We similarly recorded an impairment on the value of our ~~Predecessor~~unevaluated oil and natural gas properties in the first quarter of 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.

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Because we do not intend to book PUD reserves going forward, additional impairment charges could be recorded in connection with future acquisitions. Further, if the ~~IPO.~~

~~Acquisition Opportunities~~

~~Acquisitions are an important part~~price of ~~our growth strategy,~~oil, natural gas and NGLs decreases in future periods, we ~~expect~~may be required to pursue acquisitions of mineral and royalty interests from our Sponsors, the Contributing Parties and third parties. We also may pursue acquisitions jointly with our Sponsors and the Contributing Parties. Asrecord additional impairments as a ~~consequence of any such acquisition and acquisition‑related expense, the historical financial statements of our Predecessor will differ from our financial statements in the future.~~

~~Management Services Agreements~~

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

~~Non‑Operated Working Interest Assignment~~

Prior to the transactions that were completed in connection with the IPO, our Predecessor assigned its non‑operated working interests and associated asset retirement obligations to an affiliated entity that was not contributed to the Partnership. Asresult of the closing of its IPO and through the date of this Quarterly Report, the Partnership does not own any working interests and does not have any asset retirement obligations or any lease operating expenses as a working interest owner.full-cost ceiling limitation.

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Results of Operations

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


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

											Three Months Ended September 30,				Nine Months Ended September 30,
											2021		2020		2021		2020
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	8,351,399	$	969,084	$	20,656,741	$	318,310	$	2,572,477	$	47,638,423	$	24,325,893	$	122,844,684	$	66,686,729
Lease bonus and other income												1,722,508		15,916		3,013,041		313,844
(Loss) gain on commodity derivative instruments, net												(17,566,617)		(5,897,646)		(45,919,531)		193,995
Total revenues												31,794,314		18,444,163		79,938,194		67,194,568
Costs and expenses
Production and ad valorem taxes		778,733		120,315		1,602,520		19,651		203,567		3,104,502		1,840,607		8,100,733		4,916,858
Depreciation, depletion and accretion expense		4,488,915		418,969		11,156,292		113,639		1,244,023
Depreciation and depletion expense												8,828,517		10,704,945		25,076,429		36,002,109
Impairment of oil and natural gas properties		—		306,959		—		—		4,992,897		—		22,237,131		—		158,698,835
Marketing and other deductions		424,702		320,698		1,068,509		110,534		570,521		2,996,434		2,511,919		8,842,942		6,692,850
General and administrative expenses		2,314,718		463,501		5,707,093		532,035		1,252,001		6,766,628		6,110,846		20,247,843		19,500,306
Total costs and expenses		8,007,068		1,630,442		19,534,414		775,859		8,263,009		21,696,081		43,405,448		62,267,947		225,810,958
Operating income (loss)		344,331		(661,358)		1,122,327		(457,549)		(5,690,532)		10,098,233		(24,961,285)		17,670,247		(158,616,390)
Other income (expense)
Equity income in affiliate												261,336		292,803		719,958		460,360
Interest expense		225,302		103,596		468,429		39,307		314,081		(2,495,465)		(1,603,006)		(6,692,263)		(4,689,907)
Income (loss) before income taxes		119,029		(764,954)		653,898		(496,856)		(6,004,613)
State income taxes		—		4,212		—		—		13,401
Other (expense) income												(397,608)		(100,000)		16,347		(100,000)
Net income (loss) before income taxes												7,466,496		(26,371,488)		11,714,289		(162,945,937)
Benefit from income taxes												—		(694,864)		—		(694,864)
Net income (loss)	$	119,029	$	(769,166)	$	653,898	$	(496,856)	$	(6,018,014)		7,466,496		(25,676,624)		11,714,289		(162,251,073)
Distribution and accretion on Series A preferred units												(4,849,996)		(1,577,968)		(8,005,932)		(6,232,620)
Net (income) loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests												(761,311)		9,482,090		(1,024,655)		63,429,454
Distribution on Class B units												(17,610)		(23,141)		(59,170)		(71,089)
Net income (loss) attributable to common units											$	1,837,579	$	(17,795,643)	$	2,624,532	$	(105,125,328)
Production Data:
Oil (Bbls)		108,692		13,752		267,966		3,696		41,548		345,273		362,363		1,003,795		1,060,957
Natural gas (Mcf)		888,694		93,794		2,205,292		32,961		343,078		4,995,962		4,601,729		14,267,115		13,283,208
Natural gas liquids (Bbls)		46,493		4,850		108,929		1,220		17,458		184,591		173,392		525,486		504,066
Combined volumes (Boe) (6:1)		303,301		34,234		744,444		10,410		116,186		1,362,524		1,302,710		3,907,134		3,778,891

Comparison of the Three Months Ended September 30, ~~2017~~2021 to the Three Months Ended September 30, ~~2016~~2020

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

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

For the three months ended September 30, ~~2017,~~2021, our oil, natural gas and NGL revenues were ~~$8.4~~$47.6 million, an increase of ~~$7.4~~$23.3 million from ~~$1.0~~$24.3 million for the three months ended September 30, ~~2016.~~2020. The increase in oil, natural gas and NGL revenues was ~~primarily due~~directly related to the ~~$247.8 million acquisition of various mineral~~increase in the average prices we received for oil, natural gas and ~~royalty interests from~~NGL production for the ~~Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.~~

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three months ended September 30, 2021 as discussed below.

Our ~~and our Predecessor’s~~ revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were ~~303,301~~1,362,524 Boe or ~~3,297~~14,810 Boe/d, for the three months ended September 30, ~~2017,~~2021, an increase of ~~269,067~~59,814 Boe or ~~2,925~~650 Boe/d, from ~~34,234~~1,302,710 Boe or ~~372~~14,160 Boe/d, for the three months ended

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September 30, 2020. The increase in production for the three months ended September 30, ~~2016. The production realized~~2021 from ~~the overriding royalty interests we acquired from Maxus Energy Corporation in late April 2017 enabled us to offset natural production declines from our existing portfolio and to exit the quarter ended~~ September 30, ~~2017~~2020 was primarily attributable to production associated with ~~slightly higher production.~~the assets located in the Haynesville, Bakken and Rockies basins, partially offset by a reduction in production in the Permian basin.

Our operators received an average of ~~$43.95~~$67.47 per Bbl of oil, ~~$2.79~~$3.82 per Mcf of natural gas and ~~$19.75~~$28.42 per Bbl of NGL for the volumes sold during the three months ended September 30, ~~2017. Our Predecessor’s operators received an average of $42.08~~2021 compared to $38.36 per Bbl of oil, ~~$3.11~~$1.76 per Mcf of natural gas and ~~$20.37~~$13.42 per Bbl of NGL for the volumes sold during the three months ended September 30, ~~2016. The~~2020. These average prices received during the three months ended September 30, ~~2017~~2021 increased ~~4.4%~~75.9% or ~~$1.87~~$29.11 per Bbl of oil and ~~decreased 10.3%~~117.0% or ~~$0.32~~$2.06 per Mcf of natural gas as compared to the three months ended September 30, ~~2016. The increase in the average price received for oil~~2020. This change is consistent with ~~increase in the price of oil~~prices experienced in the market, specifically when compared to the EIA average price ~~increase~~increases of ~~7.4%~~72.6% or ~~$3.33~~$29.69 per Bbl of ~~oil.~~oil and 117.5% or $2.35 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income was $1.7 million for the three months ended September 30, 2021 compared to $0.02 million for the three months ended September 30, 2020. The ~~change~~increase in lease bonus and other income is primarily related to a $1.5 million lease bonus received during the three months ended September 30, 2021 related to properties in the ~~average price received~~Permian Basin.

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended September 30, 2021 included $11.2 million of mark-to-market losses and $6.4 million of losses on the settlement of commodity derivative instruments compared to $6.6 million of mark-to-market losses and $0.7 million of gains on the settlement of commodity derivative instruments for the three months ended September 30, 2020. We recorded a mark-to-market loss for the three months ended September 30, 2021 as a result of the increase in the strip pricing of oil and natural gas ~~was attributable~~from the three months ended June 30, 2021 to the ~~diversification~~three months ended September 30, 2021. We recorded a mark-to-market loss for the three months ended September 30, 2020 as a result of ~~our~~the increase in the strip pricing of oil and natural gas ~~producing interests when compared~~from the three months ended June 30, 2020 to the ~~natural gas producing interests of our Predecessor.~~three months ended September 30, 2020.

Production and Ad Valorem Taxes

~~Our production~~Production and ad valorem taxes for the three months ended September 30, ~~2017~~2021 were ~~$0.8~~$3.1 million, an increase of ~~$0.7~~$1.3 million from ~~$0.1~~$1.8 million infor the three months ended September 30, ~~2016.~~2020. The increase in production and ad valorem taxes was ~~attributable~~primarily related to the ~~$247.8 million acquisition of various mineral~~significant increase in the average prices we received for oil, natural gas and ~~royalty interests from~~NGL production for the ~~Contributing Parties at the closing of our IPO~~three months ended September 30, 2021.

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

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

~~Our depreciation,~~ depletion ~~and accretion~~ expense for the three months ended September 30, ~~2017~~2021 was ~~$4.5~~$8.8 million, ~~an increase~~a decrease of ~~$4.1~~$1.9 million from ~~our Predecessor’s depreciation, depletion and accretion expense of $0.4~~$10.7 million for the three months ended September 30, ~~2016.~~2020. The ~~increase~~decrease in ~~the~~ depreciation ~~depletion~~ and ~~accretion~~depletion expense was ~~primarily attributable~~due to the ~~$247.8 million acquisition of various mineral~~impairment that was recorded during the year ended December 31, 2020, which significantly reduced our net capitalized oil and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired~~natural gas properties.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a ~~units‑of‑production~~units-of-production basis. Estimates of proved developed ~~producing~~ reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was ~~$14.66~~$6.21 for the three months ended September 30, ~~2017, an increase~~2021, a decrease of ~~$4.87~~$1.95 per barrel from ~~$9.79~~the $8.16 average depletion rate per barrel for the three months ended September 30, ~~2016.~~2020. The ~~increase~~decrease in the ~~average~~ depletion rate ~~per barrel~~ was ~~primarily attributable~~due to the ~~$247.8 million acquisition of various mineral~~significant impairment that was recorded during the year ended December 31, 2020, which significantly reduced our net capitalized oil and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired~~natural gas properties.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

NoWe did not record an impairment expense ~~was recorded~~on our oil and natural gas properties for the three months ended September 30, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of2021. We recorded an impairment ofexpense on our oil and natural gas properties ~~for~~of $22.2 million during the ~~Partnership in the current period. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an~~

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three months ended September 30, 2020. The impairment ~~in 2018 after the exemption has expired.~~

~~Impairments for our Predecessor totaled $0.3 million for~~recorded during the three months ended September 30, ~~2016 primarily~~2020 was due to a significant decline in the ~~impact that declines~~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 ~~commodity prices had on the value~~March 2020 by members of ~~reserve estimates.~~OPEC and other foreign, oil-exporting countries, and other supply factors.

Marketing and Other Deductions

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increase of ~~$0.1~~$0.5 million from ~~our Predecessor’s marketing and other deductions~~$2.5 million for the three months ended September 30, 2016 of $0.3 million. The increase in marketing and other deductions was attributable to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.2020.

General and Administrative Expenses

~~Our general~~General and administrative expenses for the three months ended September 30, ~~2017~~2021 were ~~$2.3~~$6.8 million, an increase of ~~$1.8~~$0.7 million from ~~our Predecessor’s general and administrative expenses of $0.5~~$6.1 million for the three months ended September 30, ~~2016.~~2020. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to ~~the increased cost related to operating the Partnership as~~ a ~~publicly traded company.~~$0.3 million increase in unit-based compensation expense cash general and administrative expenses resulting from increases in salaries and wages and our costs associated with company growth.

Interest Expense

Interest ~~Expense~~

~~Our interest~~ expense for the three months ended September 30, ~~2017~~2021 was ~~$0.2~~$2.5 million as compared to ~~our Predecessor’s interest expense of $0.1~~$1.6 million for the three months ended September 30, ~~2016.~~2020. The increase in interest expense was primarily due to debt incurred in 2021 to fund the redemption of the Series A preferred units.

Comparison of the Nine Months Ended September 30, ~~2017~~2021 to the Nine Months Ended September 30, ~~2016~~2020

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

For the nine months ended September 30, ~~2017 includes the results of operations of~~2021, our ~~Predecessor for the Predecessor 2017 Period~~oil, natural gas and our results of operations for the period from February 8, 2017 to September 30, 2017. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

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

~~For the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period, our and our Predecessor’s~~NGL revenues were ~~$20.7 and $0.3~~$122.8 million, ~~respectively, for combined revenues~~an increase of ~~$21.0~~$56.1 million from $66.7 million for the nine months ended September 30, ~~2017, an~~2020. The increase ~~of $18.4 million, from $2.6 million~~in oil, natural gas and NGL revenues was directly related to the increase in the average prices we received for oil, natural gas and NGL production for the nine months ended September 30, 2016. The increase in revenues was primarily due to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.2021 as discussed below.

Our ~~and our Predecessor’s~~ revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were ~~744,444~~3,907,134 Boe or ~~3,168 Boe/d and 10,410 Boe or 274~~14,312 Boe/d, for the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017 and~~2021, an increase of 128,243 Boe or 520 Boe/d, from 3,778,891 Boe or 13,792 Boe/d, for the ~~Predecessor 2017 Period, respectively.~~nine months ended September 30, 2020. The ~~combined~~increase in production for the nine months ended September 30, ~~2017~~2021 was ~~754,854 Boe or 2,765 Boe/d, an~~primarily attributable to production associated with the Springbok Acquisition, which accounted for 192,024 Boe. The increase was partially offset by a reduction in production on our other assets as a result of ~~638,668 Boe or 2,341 Boe/d, from 116,186 Boe or 424 Boe/d, for~~ the nine months ended September 30, 2016. The production realized from the overriding royalty interests we acquired from Maxus Energy Corporation in late April 2017 enabled us to offset natural production declines from our existing portfolioCOVID-19 outbreak and international supply and demand imbalances and, to ~~exit~~a lesser extent, the ~~quarter ended September 30, 2017 with slightly higher production.~~winter storms experienced in parts of the United States in February 2021, which caused the temporary shut-in of certain properties in which we have an interest. See Business Environment — COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas for further discussion.

Our operators received an average of ~~$45.14~~$61.99 per Bbl of oil, ~~$2.77~~$3.28 per Mcf of natural gas and $20.85 per Bbl of NGL for the volumes sold during the period from February 8, 2017 to September 30, 2017. Our Predecessor’s operators received an average of $47.04 per Bbl of oil, $3.47 per Mcf of natural gas and $24.61 per Bbl of NGL for the volumes sold during the Predecessor 2017 Period. For the combined nine months ended September 30, 2017, the operators received an average of $45.16 per Bbl of oil, $2.78 per Mcf of natural gas and $20.90 per Bbl of NGL for the volumes sold. Our Predecessor’s operators received an average of $38.11 per Bbl of oil, $2.14 per Mcf of natural gas and $14.56$26.27 per Bbl of NGL for the volumes sold during the nine months ended September 30, ~~2016. Average prices received by~~2021 compared to $36.08 per Bbl of oil, $1.70 per Mcf of natural gas and $11.47 per Bbl of NGL for the ~~operators~~volumes sold during the ~~combined~~ nine months ended September 30, ~~2017~~2020. These average prices received during the nine months ended September 30, 2021 increased ~~18.5%~~71.8% or ~~$7.05~~$25.91 per Bbl of oil and ~~29.9%~~92.9% or ~~$0.64~~$1.58 per Mcf of natural gas as compared to the nine months ended September 30, ~~2016. These increases are~~2020. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increases of ~~19.2%~~71.0% or ~~$7.95~~$27.01 per Bbl of oil and ~~28.6%~~93.0% or ~~$0.67~~$1.74 per Mcf of natural gas for the comparable periods.

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Lease Bonus and Other Income

Lease bonus and other income increased by $2.7 million to $3.0 million for the nine months ended September 30, 2021 compared to $0.3 million for the nine months ended September 30, 2020. The increase in lease bonus and other income is primarily related to a $1.5 million lease bonus received during the nine months ended September 30, 2021, related to properties in the Permian Basin, and also due to the volatility and uncertainty experienced in the oil and gas market for the 2020 period, which discouraged operators from drilling new wells.

(Loss) Gain on Commodity Derivative Instruments

Loss on commodity derivative instruments for the nine months ended September 30, 2021 included $35.4 million of mark-to-market losses and $10.5 million of losses on the settlement of commodity derivative instruments compared to $4.5 million of mark-to-market losses and $4.7 million of gains on the settlement of commodity derivative instruments for the nine months ended September 30, 2020. We recorded a mark-to-market loss for the nine months ended September 30, 2021 as a result of the continued increase in strip pricing from December 31, 2020. The mark-to-market gain for the nine months ended September 30, 2020 was attributable to the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts, which was partially offset by the increase in volumes hedged due to the Springbok Acquisition.

Production and Ad Valorem Taxes

Our production and ad valorem taxes for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $1.6 million and $0.02 million, respectively. The combined productionProduction and ad valorem taxes for the nine months ended September 30, ~~2017~~2021 were ~~$1.6~~$8.1 million, an increase of ~~$1.4~~$3.2 million from ~~$0.2~~$4.9 million infor the nine months ended September 30, ~~2016.~~2020. The increase in production and ad valorem taxes was primarily attributable to the ~~$247.8 million acquisition of various mineral~~increase in the average prices we received for oil, natural gas and ~~royalty interests from~~NGL production for the ~~Contributing Parties at the closing of our IPO~~nine months ended September 30, 2021, and ~~the relevant~~to a lesser extent, production and ~~revenues from those acquired interests.~~ad valorem taxes associated with the Springbok Acquisition.

Depreciation and Depletion Expense

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

~~Our and our Predecessor’s depreciation,~~ depletion ~~and accretion~~ expense for the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017 and the Predecessor 2017 Period~~2021 was ~~$11.2~~$25.1 million, ~~and $0.1~~a decrease of $10.9 million ~~respectively for a combined expense of $11.3~~from $36.0 million for the nine months ended September 30, ~~2017. This was an increase of $10.1 million from our Predecessor’s~~2020. The decrease in depreciation ~~depletion~~ and ~~accretion expense of $1.2 million for the nine months ended September 30, 2016. The increase in the depreciation,~~ depletion ~~and accretion~~ expense was ~~primarily attributable~~due to the ~~$247.8 million acquisition of various mineral~~impairment that was recorded during the year ended December 31, 2020, which significantly reduced our net capitalized oil and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired~~natural gas properties.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a ~~units‑of‑production~~units-of-production basis. Estimates of proved developed ~~producing~~ reserves are a major component in the calculation of depletion. Our ~~and our Predecessor’s~~ average depletion rate per barrel was ~~$14.84 and $10.31~~$6.18 for the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017 and~~2021, a decrease of $3.29 per barrel from the ~~Predecessor 2017 Period, respectively. The combined~~$9.47 average depletion rate per barrel for the nine months ended September 30, ~~2017 was $14.78, an increase of $4.07 per barrel from an average~~2020. The decrease in the depletion rate ~~of $10.71 per barrel for the nine months ended September 30, 2016. The increase in the average depletion rate per barrel~~ was ~~primarily attributable~~due to the ~~$247.8 million acquisition of various mineral~~significant impairment that was recorded during the year ended December 31, 2020, which significantly reduced our net capitalized oil and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant production from those acquired~~natural gas properties.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

NoWe did not record an impairment expense was recorded for the period from February 8, 2017 to September 30, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment ofon our oil and natural gas properties for the ~~Partnership for the period from February 8, 2017 to~~nine months ended September 30, ~~2017. Unless there are significant changes in~~2021. We recorded an impairment expense on our oil and natural gas ~~prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired.~~

~~Impairments for our Predecessor totaled $5.0~~properties of $158.7 million ~~for~~during the nine months ended September 30, ~~2016 primarily~~2020. The impairment recorded during the nine months ended September 30, 2020 was due to a significant decline in the ~~impact that declines~~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 ~~commodity prices had on the value~~March 2020 by members of ~~reserve estimates.~~OPEC and other foreign, oil-exporting countries, and other supply factors.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a ~~post‑production expense, and our Predecessor’s marketing and other deductions also include lease operating expenses related to its non‑operated working interests.~~post-production expense. Marketing ~~and other deductions for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $1.1 million and $0.1 million, respectively. The combined marketing~~ and other deductions for the nine months ended September 30, ~~2017~~2021 were ~~$1.2~~$8.8 million, an increase of $0.6 million from our Predecessor’s marketing and other deductions for the nine months ended September 30, 2016 of $0.6 million. The increase in marketing and other deductions was attributable the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.

~~General and Administrative Expenses~~

Our and our Predecessor’s general and administrative expenses for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $5.7 million and $0.5 million, respectively. General and administrative$2.1

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~~expenses for the combined nine months ended September 30, 2017 were $6.2 million, an increase of $4.9~~ million from ~~our Predecessor’s general and administrative expenses of $1.3~~$6.7 million for the nine months ended September 30, ~~2016. The~~2020, which was primarily attributable to the increase in ~~general~~prices for oil, natural gas and NGL production.

General and Administrative Expenses

General and administrative expenses ~~was attributable to the increased costs related to operating the Partnership as a publicly traded company.~~

~~Interest Expense~~

Our and our Predecessor’s interest expense for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period was $0.5 million and $0.04 million, respectively. The interest expense for the combined nine months ended September 30, 2017 was $0.5 million as compared to our Predecessor’s interest expense of $0.3remained relatively flat at $20.2 million for the nine months ended September 30, ~~2016.~~2021 compared to $19.5 million for the nine months ended September 30, 2020.

Interest Expense

Interest expense for the nine months ended September 30, 2021 was $6.7 million compared to $4.7 million for the nine months ended September 30, 2020. The increase in interest expense was primarily due to debt incurred in 2021 to fund the redemption of the Series A preferred units.

Liquidity and Capital Resources

Overview

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

~~Our~~Cash Distribution Policy

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

~~Unlike a number~~In light of ~~other master limited partnerships, we do not generally intend~~the unprecedented global economic impact resulting from the COVID-19 pandemic, the related impact to ~~retain cash from our operations for capital expenditures necessary to replace our existing~~the United States oil and natural gas ~~reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that~~markets and the ~~continued development~~potential for further curtailments of production, the Board of Directors approved the allocation of 25% of our ~~properties~~cash available for distribution on common units for the third quarter of 2021 for the repayment of $7.6 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the third quarter of 2021. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and ~~completion~~may allocate such cash in other manners in which the Board of ~~drilled but uncompleted wells by working interest owners will substantially offset~~Directors determines to be appropriate at the ~~natural production declines from~~time. 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 ~~existing wells. If they believe it is warranted,~~quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the period(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders.change this policy.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt ~~securities, although~~securities. For example, we issued 2,224,358 common units and 2,497,134 OpCo common units and an equal number of Class B units as partial consideration in connection with the Springbok Acquisition. The

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Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, or(ii) otherwise reserve cash for distributions or to(iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

Because our partnership agreement requires us to distribute an amount equal to all available cash we generate each quarter, our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount See “Recent Developments—Quarterly Distributions” above for discussion of our quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price

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of oil, natural gas and natural gas liquids, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of our quarterly distributions may be significant and could result in our not making any distribution for any particular quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The Board of Directors may change our distribution policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters.third quarter 2021 distributions.

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

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

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

Cash Flows

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

Partnership

Predecessor

Period from February 8, 2017 to September 30,

Period from January 1, 2017 to February 7,

Nine Months Ended September 30,

2017

2017

2016

Cash Flow Data:

Cash flows provided by operating activities

$
13,965

$
187

$
957

Cash flows used in investing activities

(117,190)

(1)

(94)

Cash flows provided by (used in) financing activities

109,451

—

(563)

Net increase in cash

$
6,226

$
186

$
300


	Nine Months Ended September 30,
	2021		2020
Cash Flow Data:		��
Net cash provided by operating activities	$	69,082,654	$	47,924,350
Net cash used in investing activities		(755,777)		(88,833,570)
Net cash (used in) provided by financing activities		(65,433,098)		39,052,659
Net increase (decrease) in cash and cash equivalents	$	2,893,779	$	(1,856,561)

Operating Activities

Our ~~and our Predecessor’s~~ operating cash flow is impacted by many variables, the most significant of which ~~is the change~~are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and ~~NGL.~~NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our ~~and our Predecessor’s~~ control and are difficult to predict. Cash flows provided by operating activities for the ~~period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $14.0 million and $0.2 million, respectively. Cash flows provided by operating activities for the combined~~ nine months ended September 30, ~~2017~~2021 were ~~$14.2~~$69.1 million, an increase of ~~$13.2~~$21.2 million compared to ~~our Predecessor’s cash flows provided by operating activities of $1.0~~$47.9 million for the nine months ended September 30, ~~2016.~~2020. The increase in cash flows provided by operating activities was ~~largely~~primarily attributable to the ~~$247.8 million acquisition of various mineral~~increase in the average prices we received for oil, natural gas and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant~~NGL production ~~and revenues from those acquired interests.~~

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~~Investing Activities~~

~~Cash flows used in investing activities~~ for the ~~period from February 8, 2017 to~~nine months ended September 30, ~~2017 were $117.2 million, an increase of $117.1 million compared to our Predecessor’s cash~~2021.

Investing Activities

Cash flows used in investing activities for the nine months ended September 30, ~~2016 of $0.1 million. Our Predecessor’s cash flows used in investing activities~~2021 were ~~de minimis for the Predecessor 2017 Period. For the period from February 8, 2017 to September 30, 2017, we used the $96.2~~$0.8 million in proceeds received from our IPO to pay the cash portion of our acquisition of oil and natural gas properties at the IPO and we used $20.7 million to fund the acquisition of various mineral and royalty interests.

~~Financing Activities~~

~~Cash flows provided by financing activities was $109.5 million for the period from February 8, 2017 to September 30, 2017 as~~ compared to ~~our Predecessor’s cash used in financing activities of $0.6~~$88.8 million for the nine months ended September 30, ~~2016. Our Predecessor did not have any~~2020. For the nine months ended September 30, 2021, we used $0.7 million primarily to fund the renovation of office space and $0.5 million primarily to fund the acquisition of assets from Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP (“Oil Nut Bay”), partially offset by a $0.5 million cash distribution received in connection with a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP during the period. 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.

Financing Activities

Cash flows used in orfinancing activities were $65.4 million for the nine months ended September 30, 2021 compared to $39.1 million of cash flows provided by financing activities for the ~~Predecessor 2017 Period. During the period from February 8, 2017 to~~nine months ended September 30, ~~2017, we received $96.2~~2020. Cash flows used in financing activities for the nine months ended September 30, 2021 consists of $48.9 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $36.1 million to fund the redemption of Series A preferred units, $19.4 million used to repay borrowings under out secured revolving credit facility, $1.1 million of restricted units repurchased for tax withholding, $0.3 million payment of loan origination costs and $0.2 million paid in connection with the redemption of Class B units, partially offset by $40.6 million of additional borrowings under our secured revolving credit facility. 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 ~~IPO, we borrowed $22.2~~secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units, $42.6 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units and $0.4 million paid ~~a distribution to unitholders~~in connection with the redemption of ~~$8.7 million and paid loan origination costs~~Class B units.

Table of ~~$0.3 million.~~ Contents

Capital Expenditures

During the nine months ended September 30, ~~2016, our Predecessor repaid $0.6~~2021, we paid approximately $0.5 million ~~on its long‑term debt.~~

~~Capital Expenditures~~

~~During the period from February 8, 2017 to September 30, 2017, we acquired mineral and royalty interests from the Contributing Parties for common units~~primarily in connection with ~~a total value at the IPO of $169.1 million and $96.2 million in cash. Additionally, we spent an aggregate amount of $20.7 million for~~ the acquisition of ~~various mineral~~assets from Nail Bay Royalties and royalty interests. During the Predecessor 2017 Period, our Predecessor spent $523 on additional lease and well equipment and intangible drilling costs related to the Predecessor’s working interests and office equipment.Oil Nut Bay. During the nine months ended September 30, ~~2016, our Predecessor spent $0.1~~2020, we paid approximately $87.5 million ~~on additional lease and well equipment and intangible drilling costs related to~~primarily in connection with the ~~Predecessor’s working interests and office equipment.~~Springbok Acquisition.

Indebtedness

~~Revolving Credit Agreement~~

WeOn January 11, 2017, we entered into a ~~$50.0 million revolving~~ credit ~~facility in connection~~agreement (the “2017 Credit Agreement”) with ~~our IPO, which is secured by substantially all of our assets~~Frost Bank, as administrative agent, and the ~~assets of our wholly owned subsidiaries.~~lenders party thereto. On July 12, 2018 we entered into an amendment (the “First Credit Agreement Amendment”) to the 2017 Credit Agreement (the 2017 Credit Agreement as amended by the First Credit Agreement Amendment, the “2018 Amended Credit Agreement”). On December 8, 2020, we entered into the Second Credit Agreement Amendment to the 2018 Amended Credit Agreement (the 2018 Amended Credit Agreement as amended by the Second Credit Agreement Amendment, the “Amended Credit Agreement”). Under the Amended Credit Agreement, availability under our secured revolving credit facility ~~availability under the facility~~ will continue to equal the lesser of the aggregate maximum elected commitments of the lenders, which may be increased up to $500.0 million, subject to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders, and the borrowing base. The Second Credit Agreement Amendment amended the 2018 Amended Credit Agreement to extend the maturity date thereunder from February 8, 2022 to June 7, 2024.

The Second Credit Agreement Amendment increased aggregate commitments under the 2018 Amended Credit Agreement from $225.0 million to $265.0 million providing for maximum availability of $265.0 million. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million, subject to the limitations of our borrowing base and satisfaction of certain conditions, including the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders and the borrowing base. In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be ~~re-determined semi-annually~~redetermined semiannually on ~~February~~May 1 and ~~August~~November 1 of each year, beginning May 1, 2021, based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries. The secured revolving credit facility permits aggregate commitments under the facility to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. In connection with the ~~August~~May 1, 2021 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at ~~$100.0~~$265.0 million. ~~Aggregate commitments remain at $50.0 million providing for maximum availability under~~The November borrowing base redetermination is currently being conducted and is expected to be finalized by the ~~revolving credit facility~~end of ~~$50.0 million.~~November 2021.

The ~~secured revolving credit facility~~Amended Credit Agreement 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 and OpCo 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~~Amended Credit Agreement 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~~3.5 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~~Amended Credit Agreement also contains customary events of default, including ~~non‑payment,~~non-payment, breach of covenants, materially incorrect representations, ~~cross‑~~cross default, bankruptcy and change of control. As of ~~November 8, 2017,~~September 30, 2021, we ~~have borrowed $29.6~~had outstanding borrowings of $192.7 million under the secured revolving credit facility and $72.3 million of available capacity.

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

Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our entrance into a management services agreement with Kimbell Operating Company, LLC and the acquisition of various mineral and royalty interests for an aggregate purchase price of approximately $28.1 million.

net taxable income. We currently expect that (i) we will pay no material federal income taxes through 2027

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~~Predecessor Credit Facility~~

On January 31, 2014, our Predecessor entered into a credit agreement with Frost Bank for a $50.0 million credit facility. The credit facility was subject to borrowing base restrictions and was collateralized by certain properties. The borrowing base was $20 million with interest payable monthly on Alternate Base Rate loans or at the end(no more than approximately 5% of the interest period on any Eurodollar loans. As of December 31, 2016, our Predecessor’s total indebtedness under its credit facility was approximately $10.6 million, with an average interest rate of 3.39%. The credit facility was to mature in January 2018. The credit facility contained certain restrictive covenants. As of December 31, 2016, the Predecessor was in compliance with all of the covenants included in the credit facility. On February 8, 2017, our Predecessor repaid the entire outstanding principal and interest balance on the credit facility withestimated pre-tax distributable cash ~~proceeds from the contribution of our Predecessor’s mineral and royalty interests to the Partnership. We did not assume any indebtedness of our Predecessor in connection with the IPO.~~

~~Internal Controls and Procedures~~

~~We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes‑Oxley Act of 2002 (“Sarbanes-Oxley Act”)~~flow), and ~~are therefore not required~~(ii) substantially all distributions (more than 95%) paid to ~~make a formal assessment of the effectiveness of~~ our internal controls over financial reporting for that purpose. We are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes‑Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2018. To comply with the requirements of being a public company, we will need to implement additional controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

~~Further, our independent registered public accounting firm is not yet required to attest to the effectiveness of our internal controls over financial reporting, and~~common unitholders will not be ~~required to do so for~~taxable dividend income through 2025.

Distributions in excess of the amount taxable as ~~long as we are an “emerging growth company” pursuant~~dividend income will reduce a common unitholder's tax basis in its common units or produce capital gain to the ~~provisions~~extent they exceed a common unitholder's tax basis. Any reduced tax basis will increase a common unitholder's capital gain when it sells its common units. The estimates described above are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax "earnings and profits." Our estimates of the ~~Jumpstart Our Business Act (“JOBS Act”)~~tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company allocated to us. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which we operate. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as ~~long as we~~being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are ~~a non‑accelerated filer.~~encouraged to consult with your tax advisor on this matter.

New and Revised Financial Accounting Standards

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

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

Critical Accounting Policies and Related Estimates

~~The discussion and analysis of our financial condition and results of operations are based upon the historical financial statements of our Predecessor, which~~There have been ~~prepared in accordance with GAAP. Certain of~~no substantial changes to our critical accounting policies ~~involve judgments~~ and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accountingrelated estimates ~~including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity~~from those previously disclosed in our 2020 Form 10-K.

Contractual Obligations and ~~judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.~~

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

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~~Inflation~~

Inflation in the United States has been relatively low in recent years and did not have a material impact on our or our Predecessor’s results of operations for the period from January 1, 2016 through September 30, 2017.

~~Off‑Balance~~Off-Balance Sheet Arrangements

~~As of September 30, 2017, neither we, nor our Predecessor had any off‑balance sheet arrangements other than operating leases. As of September 30, 2017, there~~There have been no significant changes to our contractual obligations previously disclosed in our 2020 Form 10-K. As of September 30, 2021, we did not have any off-balance sheet arrangements. See Note 7—Leases to the ~~Partnership’s Annual Report on Form 10-K~~unaudited interim condensed consolidated financial statements for ~~the year ended December 31, 2016.~~additional information regarding our operating leases.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

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.

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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 interim condensed consolidated financial statements in Item 1 of this Quarterly Report for additional information regarding our commodity derivatives.

Counterparty and Customer Credit Risk

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

~~Credit Risk~~September 30, 2021, we had three counterparties to our derivative contracts, which are also lenders under our secured revolving credit facility.

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

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of September 30, ~~2017,~~2021, we had total borrowings outstanding under our secured revolving credit facility of ~~$22.2~~$192.7 million. The impact of a 1% increase in the interest rate on this amount of debt ~~would~~could result in an increase in interest expense of approximately ~~$0.2~~$1.9 million annually, assuming that our indebtedness remained constant throughout the year. ~~We do not currently have any~~

On January 27, 2021, we entered into an interest rate ~~hedges~~swap with Citibank, which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility (which represented approximately 78% of our outstanding balance as of September 30, 2021), at approximately 3.9% for the period ending on January 29, 2024. We use an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of our secured revolving credit facility from a floating to a fixed rate. For the three and nine months ended September 30, 2021, we recognized a $0.1 million loss and $0.3 million gain on interest rate swaps, respectively, which are included in ~~place.~~other income in the accompanying unaudited interim condensed consolidated statements of operations.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule ~~13a‑15(b)~~13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of the management of our ~~general partner,~~General Partner, including our ~~general partner’s~~General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules ~~13a‑15(e)~~13a-15(e) and ~~15d‑15(e)~~15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our ~~general partner’s~~General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our ~~general partner’s~~General Partner’s management, including its principal executive officer and principal financial officer concluded that as of September 30, 2021, our disclosure controls and procedures were effective ~~as of September 30, 2017.~~in ensuring that all information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to our General Partner’s management, including its principal executive officer and principal financial officer, in a manner that allows timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There ~~were no~~have not been any changes in our internal control over financial reporting that occurred during the quarter ended September 30, ~~2017~~2021 that have 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 14—Commitments and Contingencies to the unaudited interim condensed consolidated financial statements included in Part I of this Quarterly Report and incorporated by reference herein.

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

Item 1A. Risk Factors

In addition to the ~~other information set forth~~risks and uncertainties discussed in this ~~report,~~Quarterly Report, particularly the risk factor disclosed below and those disclosed in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks under the heading “Risk Factors” in ~~our 2016 Annual Report on Form 10-K. There have been no material changes to the risk factors previously discussed in~~Part I, Item ~~1A—~~1A. Risk Factors in ~~the Partnership’s 2016~~our 2020 Form 10~~-K.~~10-K. 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.

We will be subject to a number of uncertainties while we pursue the initial public offering of Kimbell Tiger Acquisition Corporation (“TGR”), and during the timeframe when TGR pursues a business combination, which could adversely affect our business, financial condition, results of operations, cash flows and common unit price.

While we have announced our intention to pursue an initial public offering of TGR, a newly formed special purpose acquisition company (“SPAC”) and our subsidiary, there has recently been heightened regulatory focus on SPACs, including recently issued accounting guidance, resulting in substantial uncertainty in the SPAC markets. There is no assurance that we will be able to consummate TGR’s initial public offering on favorable terms or at all. Further, in the event the initial public offering of TGR is completed, accounting guidance applicable to SPACs could be revisited, potentially necessitating restatements of TGR’s financial statements, which could then impact and necessitate restatements of our financial statements, as well as leading to delays as TGR pursues a suitable business transaction and requiring us to devote extensive management and employee attention and resources to these matters.

If we are unable to consummate TGR’s initial public offering on favorable terms or at all, or if we complete the initial public offering and TGR is unable to consummate a suitable business transaction during the prescribed time period, we may experience negative reactions from the financial markets and from our unitholders. In addition, in the event that TGR is able to find a suitable business combination, or if the business combination is unsuccessful, there is no assurance that we will realize the anticipated value from such transaction. Further, we will be required to devote significant management and employee attention and resources to matters relating to the initial public offering and the business combination. These matters have the potential to disrupt us from conducting business operations or pursuing other business strategies and could adversely affect our business, financial condition, results of operations and cash flows.

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Item 6. Exhibits

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

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~~EXHIBIT INDEX~~

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

*	—filed herewith

**	—furnished herewith

* —filed herewith

** —furnished herewith

3338

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~~SIGNATURES~~

SIGNATURES

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


	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner

Date: November ~~9, 2017~~4, 2021	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: November ~~9, 2017~~4, 2021	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer

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

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


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

Unit-based compensation		—		50,422

Net loss		—		(496,856)

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


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

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

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

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

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

Distributions to unitholders		—		(8,705,333)

Unit-based compensation		177,091		569,889

Net income		—		653,898

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


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


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