UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, ~~2021~~2022 OR

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

For the transition period from to

Commission file number: 001-38005

Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)


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

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

(817) 945-9700

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

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


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

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

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

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


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

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

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

As of April ~~30, 2021,~~29, 2022, the registrant had outstanding ~~39,748,270~~57,331,833 common units representing limited partner interests and ~~20,779,781~~8,211,579 Class B units representing limited partner interests.

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS


PART I – FINANCIAL INFORMATION
Item 1. ~~Condensed~~ Consolidated Financial Statements (Unaudited):	1
~~Condensed~~ Consolidated Balance Sheets	1
~~Condensed Consolidated Statements of Operations~~	2
~~Condensed~~ Consolidated Statements of Operations	3
Consolidated Statements of Changes in Unitholders’ Equity	34
~~Condensed~~ Consolidated Statements of Cash Flows	45
Notes to ~~Condensed~~ Consolidated Financial Statements	57
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	1622
Item 3. Quantitative and Qualitative Disclosures About Market Risk	3138
Item 4. Controls and Procedures	3239


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	3340
Item 1A. Risk Factors	3340
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	3340
Item 6. Exhibits	3442
Signatures	3543

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. ~~Condensed~~ Consolidated Financial Statements (Unaudited)

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

~~CONDENSED~~ CONSOLIDATED BALANCE SHEETS

(Unaudited)

March 31,

December 31,

2021

2020
ASSETS

Current assets

Cash and cash equivalents

$
8,124,335

$
9,804,977
Oil, natural gas and NGL receivables

24,768,091

17,552,756
Accounts receivable and other current assets

1,557,818

973,956
Total current assets

34,450,244

28,331,689
Property and equipment, net

2,111,648

1,964,660
Investment in affiliate (equity method)

5,048,254

5,134,951
Oil and natural gas properties

Oil and natural gas properties, using full cost method of accounting ($208,157,655 and $225,681,626 excluded from depletion at March 31, 2021 and December 31, 2020, respectively)

1,149,587,975

1,149,095,232
Less: accumulated depreciation, depletion and impairment

(635,786,468)

(628,102,279)
Total oil and natural gas properties, net

513,801,507

520,992,953
Right-of-use assets, net

3,071,305

3,123,454
Derivative assets

697,068

—
Loan origination costs, net

4,799,491

5,086,486
Total assets

$
563,979,517

$
564,634,193

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY

Current liabilities

Accounts payable

$
1,042,416

$
888,735
Other current liabilities

3,672,874

4,765,161
Derivative liabilities

11,112,053

3,113,178
Total current liabilities

15,827,343

8,767,074
Operating lease liabilities, excluding current portion

2,796,946

2,848,452
Derivative liabilities

8,540,050

3,167,685
Long-term debt

168,534,231

171,550,142
Total liabilities

195,698,570

186,333,353
Commitments and contingencies (Note 15)

Mezzanine equity:

Series A preferred units (55,000 units issued and outstanding as of March 31, 2021 and December 31, 2020)

43,281,567

42,666,102
Unitholders' equity:

Common units (39,769,896 units and 38,918,689 units issued and outstanding as of March 31, 2021 and December 31, 2020, respectively)

251,263,288

257,593,307
Class B units (20,779,781 units issued and outstanding as of March 31, 2021 and December 31, 2020, respectively)

1,038,989

1,038,989
Total unitholders' equity

252,302,277

258,632,296
Noncontrolling interest

72,697,103

77,002,442
Total equity

324,999,380

335,634,738
Total liabilities, mezzanine equity and unitholders' equity

$
563,979,517

$
564,634,193


	March 31,		December 31,
	2022		2021
ASSETS
Current assets
Cash and cash equivalents	$	10,587,893	$	7,052,414
Oil, natural gas and NGL receivables		41,556,172		35,147,145
Derivative assets		2,102,159		166,307
Accounts receivable and other current assets		2,320,933		3,051,593
Total current assets		56,567,157		45,417,459
Property and equipment, net		1,529,693		1,888,247
Investment in affiliate (equity method)		4,560,360		4,738,822
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($134,586,442 and $153,284,173 excluded from depletion at March 31, 2022 and December 31, 2021, respectively)		1,204,805,739		1,204,395,484
Less: accumulated depreciation, depletion and impairment		(673,991,373)		(663,603,142)
Total oil and natural gas properties, net		530,814,366		540,792,342
Right-of-use assets, net		2,766,972		2,844,997
Derivative assets		3,457,466		1,590,501
Loan origination costs, net		3,942,281		4,214,484
Assets of consolidated variable interest entities:
Cash		2,953,876		—
Investments held in trust		237,001,386		—
Prepaid expenses		490,485		—
Total assets	$	844,084,042	$	601,486,852

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	1,893,672	$	811,019
Other current liabilities		3,782,668		3,319,495
Derivative liabilities		43,316,700		24,190,678
Total current liabilities		48,993,040		28,321,192
Operating lease liabilities, excluding current portion		2,482,028		2,561,274
Derivative liabilities		7,548,566		4,190,776
Long-term debt		226,515,911		217,115,911
Other liabilities		416,667		447,918
Liabilities of consolidated variable interest entities:
Accounts payable		60,995		—
Other current liabilities		465,607		—
Deferred underwriting commissions		8,050,000		—
Total liabilities		294,532,814		252,637,071
Commitments and contingencies (Note 14)
Mezzanine equity:
Redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation		236,900,000		—
Kimbell Royalty Partners, LP unitholders' equity:
Common units (57,290,923 units and 47,162,773 units issued and outstanding as of March 31, 2022 and December 31, 2021, respectively)		462,220,882		328,717,841
Class B units (8,253,660 and 17,611,579 units issued and outstanding as of March 31, 2022 and December 31, 2021, respectively)		412,683		880,579
Total Kimbell Royalty Partners, LP unitholders' equity		462,633,565		329,598,420
Noncontrolling (deficit) interest in OpCo		(149,982,337)		19,251,361
Total equity		312,651,228		348,849,781
Total liabilities, mezzanine equity and unitholders' equity	$	844,084,042	$	601,486,852

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 March 31,

2021

2020
Revenue

Oil, natural gas and NGL revenues

$
36,368,510

$
25,585,439
Lease bonus and other income

186,308

229,319
(Loss) gain on commodity derivative instruments, net

(14,135,728)

10,132,613
Total revenues

22,419,090

35,947,371
Costs and expenses

Production and ad valorem taxes

2,431,830

1,621,743
Depreciation and depletion expense

7,911,148

13,270,683
Impairment of oil and natural gas properties

—

70,925,731
Marketing and other deductions

3,295,286

2,131,552
General and administrative expense

6,796,385

6,524,311
Total costs and expenses

20,434,649

94,474,020
Operating income (loss)

1,984,441

(58,526,649)
Other income (expense)

Equity income in affiliate

185,080

163,554
Interest expense

(2,095,098)

(1,421,304)
Other income

462,771

—
Net income (loss) before income taxes

537,194

(59,784,399)
Provision for income taxes

—

—
Net income (loss)

537,194

(59,784,399)
Distribution and accretion on Series A preferred units

(1,577,968)

(3,076,684)
Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests

357,179

23,584,856
Distribution on Class B units

(20,780)

(24,807)
Net loss attributable to common units

$
(704,375)

$
(39,301,034)

Net loss attributable to common units

Basic

$
(0.02)

$
(1.29)
Diluted

$
(0.02)

$
(1.29)
Weighted average number of common units outstanding

Basic

37,693,469

30,528,819
Diluted

37,693,469

30,528,819


	Three Months Ended March 31,
	2022		2021
Revenue
Oil, natural gas and NGL revenues	$	65,083,903	$	36,368,510
Lease bonus and other income		654,130		186,308
Loss on commodity derivative instruments, net		(31,983,520)		(14,135,728)
Total revenues		33,754,513		22,419,090
Costs and expenses
Production and ad valorem taxes		4,020,911		2,431,830
Depreciation and depletion expense		10,759,164		7,911,148
Marketing and other deductions		3,508,066		3,295,286
General and administrative expense		6,589,259		6,796,385
Consolidated variable interest entities related:
General and administrative expense		739,459		—
Total costs and expenses		25,616,859		20,434,649
Operating income		8,137,654		1,984,441
Other income (expense)
Equity income in affiliate		249,408		185,080
Interest expense		(2,877,855)		(2,095,098)
Other income		3,068,450		462,771
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		101,386		—
Net income before income taxes		8,679,043		537,194
Provision for income taxes		271,799		—
Net income		8,407,244		537,194
Distribution and accretion on Series A preferred units		—		(1,577,968)
Net (income) loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests in OpCo		(1,058,677)		357,179
Distribution on Class B units		(17,610)		(20,780)
Net income (loss) attributable to common units of Kimbell Royalty Partners, LP	$	7,330,957	$	(704,375)

Net loss per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	(0.20)	$	(0.02)
Diluted	$	(0.20)	$	(0.02)
Weighted average number of common units outstanding
Basic		45,942,829		37,693,469
Diluted		45,942,829		37,693,469

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)

Three Months Ended March 31, 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


	Three Months Ended March 31, 2022
									Noncontrolling		Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest in OpCo		Interest in TGR		Total
Balance at January 1, 2022		47,162,773	$	328,717,841		17,611,579	$	880,579	$	19,251,361	$	—	$	348,849,781
Costs associated with equity offering		—		(325,508)		—		—		—		—		(325,508)
Conversion of Class B units to common units		9,357,919		161,424,103		(9,357,919)		(467,896)		(161,424,103)		—		(467,896)
Restricted units repurchased for tax withholding		(193,604)		(3,344,828)		—		—		—		—		(3,344,828)
Unit-based compensation		963,835		2,194,342		—		—		—		—		2,194,342
Distributions to unitholders		—		(17,450,226)		—		—		(6,516,284)		—		(23,966,510)
Distribution on Class B units		—		(17,610)		—		—		—		—		(17,610)
Proceeds from issuance of TGR public warrants		—		—		—		—		—		11,500,000		11,500,000
Accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation		—		(16,325,799)		—		—		(2,351,988)		(11,500,000)		(30,177,787)
Net income		—		7,348,567		—		—		1,058,677		—		8,407,244
Balance at March 31, 2022		57,290,923	$	462,220,882		8,253,660	$	412,683	$	(149,982,337)	$	—	$	312,651,228


	Three Months Ended March 31, 2020												Three Months Ended March 31, 2021
									Noncontrolling												Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total		Common Units		Amount		Class B Units		Amount		Interest in OpCo		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)
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		946,638		2,107,587		—		—		—		2,107,587		936,567		2,692,494		—		—		—		2,692,494
Distributions to unitholders		—		(11,122,088)		—		—		(9,616,966)		(20,739,054)		—		(7,394,551)		—		—		(3,948,160)		(11,342,711)
Distribution and accretion on Series A preferred units		—		(1,922,344)		—		—		(1,154,340)		(3,076,684)		—		(1,036,432)		—		—		(541,536)		(1,577,968)
Distribution on Class B units		—		(24,807)		—		—		—		(24,807)		—		(20,780)		—		—		—		(20,780)
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
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

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)

Three Months Ended March 31,

2021

2020
CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss)

$
537,194

$
(59,784,399)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation and depletion expense

7,911,148

13,270,683
Impairment of oil and natural gas properties

—

70,925,731
Amortization of right-of-use assets

71,785

67,470
Amortization of loan origination costs

371,487

266,318
Equity income in affiliate

(185,080)

(163,554)
Cash distribution from affiliate

216,738

—
Unit-based compensation

2,692,494

2,107,587
Loss (gain) on derivative instruments, net of settlements

12,674,172

(8,978,861)
Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

(7,215,335)

4,913,049
Accounts receivable and other current assets

(583,862)

(508,985)
Accounts payable

153,681

(450,579)
Other current liabilities

(1,092,287)

(809,594)
Operating lease liabilities

(71,142)

(67,260)
Net cash provided by operating activities

15,480,993

20,787,606
CASH FLOWS FROM INVESTING ACTIVITIES

Purchases of property and equipment

(373,947)

(40,596)
Purchase of oil and natural gas properties

(492,743)

(197,700)
Deposits on oil and natural gas properties

—

(9,681,408)
Investment in affiliate

—

(1,274,900)
Cash distribution from affiliate

55,039

17,961
Net cash used in investing activities

(811,651)

(11,176,643)
CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from equity offering

—

73,601,668
Redemption of Class B contributions on converted units

—

(245,678)
Redemption on Series A preferred units

—

(61,089,600)
Distributions to common unitholders

(7,394,551)

(11,122,088)
Distribution to OpCo unitholders

(3,948,160)

(9,616,966)
Distribution and accretion on Series A preferred units

(962,503)

(1,925,000)
Distribution on Class B units

(20,780)

(24,807)
Borrowings on long-term debt

484,089

71,088,125
Repayments on long-term debt

(3,500,000)

(70,000,000)
Payment of loan origination costs

(84,492)

—
Restricted units repurchased for tax withholding

(923,587)

—
Net cash used in financing activities

(16,349,984)

(9,334,346)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS

(1,680,642)

276,617
CASH AND CASH EQUIVALENTS, beginning of period

9,804,977

14,204,250
CASH AND CASH EQUIVALENTS, end of period

$
8,124,335

$
14,480,867
Supplemental cash flow information:

Cash paid for interest

$
1,673,361

$
1,126,666
Non-cash investing and financing activities:

Non-cash deemed distribution to Series A preferred units

$
615,465

$
1,151,684
Noncash effect of Series A preferred unit redemption

$
—

$
25,847,891


	Three Months Ended March 31,
	2022		2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	8,407,244	$	537,194
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense		10,759,164		7,911,148
Amortization of right-of-use assets		78,025		71,785
Amortization of loan origination costs		442,399		371,487
Equity income in affiliate		(249,408)		(185,080)
Cash distribution from affiliate		385,326		216,738
Unit-based compensation		2,194,342		2,692,494
Loss on derivative instruments, net of settlements		18,680,995		12,674,172
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(6,409,027)		(7,215,335)
Accounts receivable and other current assets		730,660		(583,862)
Accounts payable		1,082,653		153,681
Other current liabilities		463,173		(1,092,287)
Operating lease liabilities		(79,246)		(71,142)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		(101,386)		—
Other assets and liabilities		(352,441)		—
Net cash provided by operating activities		36,032,473		15,480,993
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(43,628)		(373,947)
Purchase of oil and natural gas properties		(410,257)		(492,743)
Cash distribution from affiliate		42,544		55,039
Consolidated variable interest entities related:
Investments in marketable securities		(236,900,000)		—
Net cash used in investing activities		(237,311,341)		(811,651)
CASH FLOWS FROM FINANCING ACTIVITIES
Costs associated with equity offering		(325,508)		—
Redemption of Class B contributions on converted units		(467,896)		—
Distributions to common unitholders		(17,450,226)		(7,394,551)
Distribution to OpCo unitholders		(6,516,284)		(3,948,160)
Distribution and accretion on Series A preferred units		—		(962,503)
Distribution on Class B units		(17,610)		(20,780)
Borrowings on long-term debt		19,100,000		484,089
Repayments on long-term debt		(9,700,000)		(3,500,000)
Payment of loan origination costs		(170,196)		(84,492)
Restricted units repurchased for tax withholding		(3,344,828)		(923,587)
Consolidated variable interest entities related:
Proceeds from initial public offering of Kimbell Tiger Operating Company		227,585,000		—
Payment of underwriting commissions with equity offering of Kimbell Tiger Operating Company		(924,229)		—
Net cash provided by (used in) financing activities		207,768,223		(16,349,984)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		6,489,355		(1,680,642)
CASH AND CASH EQUIVALENTS, beginning of period		7,052,414		9,804,977
CASH AND CASH EQUIVALENTS, end of period	$	13,541,769	$	8,124,335
Supplemental cash flow information:
Cash paid for interest	$	2,240,972	$	1,673,361
Non-cash investing and financing activities:
Noncash deemed distribution to Series A preferred units	$	—	$	615,465
Recognition of tenant improvement asset	$	31,250	$	—
Consolidated variable interest entities related:
Deferred underwriting commissions	$	8,050,000	$	—

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS —(Continued)

(Unaudited)


	Three Months Ended March 31,
	2022		2021
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows
Cash and cash equivalents	$	10,587,893	$	8,124,335
Cash held at consolidated variable interest entities		2,953,876		—
	$	13,541,769	$	8,124,335

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

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~~KIMBELL ROYALTY PARTNERS, LP~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

On February 8, 2022, the Partnership announced the $230 million initial public offering of its special purposed acquisition corporation, Kimbell Tiger Acquisition Corporation (NYSE: TGR).

Kimbell Tiger Acquisition Corporation (“TGR”) was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”), which is a subsidiary of the Partnership, was created to assist TGR in sourcing, analyzing and consummating acquisition opportunities for that initial business combination.

TGR Sponsor and TGR have been consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021. This resulted in the consolidation of $240.4 million of assets, $8.6 million of liabilities, $236.9 million of redeemable noncontrolling interests and $16.3 million of common equity and $2.4 million of noncontrolling interests related to TGR and TGR Sponsor as of March 31, 2022. Further details on the impacts of the consolidation of TGR and TGR Sponsor can be found in Note 3.

Basis of Presentation

The accompanying unaudited interim ~~condensed~~ consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange ~~Commission.~~Commission (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 Annual Report on Form 10-K for the year ended December 31, ~~2020,~~2021 (the “2021 Form 10-K”), which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the General Partner, the unaudited interim ~~condensed~~ consolidated financial statements contain all adjustments necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP and all adjustments are of a normal recurring nature. The accompanying unaudited interim consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries. 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.

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Use of Estimates

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

Segment Reporting

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

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

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

~~The global spread of coronavirus~~Coronavirus (“COVID-19”) ~~created significant volatility,~~remains a global health crisis and there continues to be considerable uncertainty and economic disruption beginning in the first three months of 2020. On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, the Partnership’s oil, natural gas, and NGL operators and other parties with whom the Partnership has business relations, including a significant reduction in the global demand for oil and natural gas. This significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance led to a significantly weaker outlook for oil and gas producers in 2020.

The Partnership has modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention (the “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 its employees to work from home toregarding the extent ~~possible. Beginning in mid-May 2020, the Partnership opened~~to which COVID-19 and its ~~offices to employees on a voluntary basis, with employees having the option to work from the office or from home. The Partnership~~variants will continue to ~~give employees~~spread. Despite improvements in global economic activity levels and higher energy demand compared to 2021, the ~~option~~impacts of COVID-19 continue to ~~work from~~be unpredictable, including the ~~office~~impacts of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. The Partnership is unable to reasonably estimate the period of time that related conditions could exist or ~~from home until~~ the ~~CDC recommends businesses and employers resume~~extent to ~~pre-pandemic operations. These restrictions have had minimal~~which they could impact on the Partnership’s business, results of operations, ~~to date and~~financial condition or cash flows. Commodity prices have ~~allowed~~risen from 2021; however, further negative impacts from COVID-19 may require the Partnership to ~~maintain the engagement and connectivity of~~adjust its ~~personnel, as well as minimize the number of employees in the office.~~business plan.

The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on the Partnership’s business, cash flows, liquidity, financial condition and results of operations ~~will depend~~remain dependent on a number of factors, ~~including, among others,~~such as the ~~ultimate severity of COVID-19, the consequences of governmental~~duration and ~~other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration~~scope of the pandemic, ~~actions taken by members~~the length and severity of ~~OPEC~~the worldwide economic downturn, the ability of the Organization of Petroleum Exporting Countries, Russia and other ~~foreign, oil-exporting countries, governmental authorities~~crude oil producing nations to manage the global crude oil supply, additional actions by businesses and ~~other thirds parties, workforce availability,~~governments in response to the pandemic, the economic downturn and the ~~timing~~decrease in crude oil demand, the speed and ~~extent~~effectiveness of ~~any return~~responses to ~~normal~~combat the virus and the time necessary to balance crude oil supply and demand to restore crude oil pricing. Although prices have recovered, the ongoing impact of COVID-19 on our business, employees and operations, including supply chain concerns, among others still continues to affect our industry.

Russia / Ukraine Conflict

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and ~~operating conditions.~~political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s ~~Annual Report on~~2021 Form 10-K, ~~for the year ended December 31, 2020,~~ 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 months ended March 31, ~~2021, other than those discussed below in~~ 2022~~Recently Adopted Accounting Pronouncements.~~.

~~Recently Adopted Accounting Pronouncements~~Consolidation

In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The Partnership ~~adopted this update on January 1, 2021~~analyzes whether it has a variable interest in an entity and ~~applied~~whether that entity is a variable interest entity (“VIE”) to determine whether it ~~prospectively.~~is required to consolidate those entities. The ~~adoption~~Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of ~~this update did~~all entities where the Partnership serves as the sponsor, general partner or managing member, and general partner entities not ~~have a material impact on the Partnership’s results of operations for the three months ended March 31, 2021.~~

wholly owned by

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~~KIMBELL ROYALTY PARTNERS, LP~~the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.

~~(Unaudited)~~For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.

VIEs for which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represent an actively-traded money market fund of TGR, a consolidated special purpose acquisition company, which investments are invested in U.S. Treasury securities purchased with funds raised through the TGR IPO (as defined below). Investments held in trust are classified as trading securities and are presented on the balance sheet at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in other income (expense)—interest income on the accompanying unaudited interim consolidated statements of operations. The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represent the shares of TGR Class A common stock (as defined below) sold in the TGR IPO (as defined below) that are redeemable for cash by the public shareholders in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests are initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. The carrying amount was accreted to its full redemption value at March 31, 2022.

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

Acquisitions

On ~~March 10,~~December 7, 2021, the Partnership completed the acquisition of all of the equity interests in certain ~~mineral~~subsidiaries owned by Caritas Royalty Fund LLC and ~~royalty assets held by Nail Bay Royalties, LLC (“Nail Bay Royalties”~~certain of its affiliates (the “Cornerstone Acquisition”) ~~and Oil Nut Bay Royalties, LP~~ for ~~a total~~an aggregate purchase price of ~~$0.5~~approximately $54.6 million. The Partnership funded the payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired ~~were managed by Nail Bay Royalties~~in the Cornerstone Acquisition consisted of

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approximately 26,000 gross producing wells across the Permian, Mid-Continent, Haynesville and ~~Duncan Management, LLC (“Duncan Management”). See Note 13—Related Party Transactions, for further discussion of the Partnership’s relation to each entity.~~other leading United States basins.

Joint ~~Ventures~~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 ~~$15.0 million.~~its current investment of $5.1 million, as noted below. The Joint Venture is managed by Springbok Operating Company, ~~LLC.~~LLC (“Springbok Operating”). While certain members of Springbok Operating are affiliated with the entities acquired as part of the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (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 March 31, ~~2021,~~2022, the Partnership had paid approximately ~~$5.2~~$5.1 million under its capital commitment. On April 29, 2022, the Joint Venture completed the sale of all of its royalty, mineral and overriding interests. See Note 15—Subsequent Events, for further discussion.

Special Purpose Acquisition Company

On July 29, 2021, TGR, the Partnership’s special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the SEC. On February 8, 2022, TGR consummated its initial public offering (the “TGR IPO”) of 23,000,000 units (each a “unit” and, collectively, the “units”), including 3,000,000 additional units issued pursuant to the underwriter’s exercise in full of its over-allotment option, at $10.00 per unit, generating proceeds of approximately $230,000,000 and incurring offering costs of approximately $12,650,000, inclusive of $8,050,000 in deferred underwriting commissions. Each unit consists of one share of Class A common stock, par value $0.0001 (the “TGR Class A common stock”), and one-half of one redeemable warrant. Each whole warrant may be exercised for one share of Class A common stock at a price of $11.50 per share. Certain members of our management and members of the Board of Directors are members of the sponsor of TGR, TGR Sponsor. TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses (the “Business Combination”). Under the terms of TGR’s governing documents, TGR has 15 months (or up to 21 months under certain circumstances) from the closing of the TGR IPO to complete the Business Combination.

In connection with the closing of the TGR IPO, TGR completed the sale of 14.1 million private placement warrants (the “private placement warrants”) to TGR Sponsor, which is a subsidiary of the Partnership, for a purchase price of $1.00 per private placement warrant, generating gross proceeds of $14.1 million. Each private placement warrant is exercisable to purchase for $11.50 1 share of TGR Class A common stock.

In addition, TGR incurred $12.7 million of fees and expenses, of which $8.1 million were deferred underwriting commissions that will become payable to the underwriters solely in the event that TGR completes the Business Combination, which were included in deferred underwriting commissions on the accompanying unaudited interim consolidated balance sheet at March 31, 2022.

In May 2021, prior to TGR’s IPO, TGR Sponsor paid $25,000 in exchange for the issuance of (i) 5,750,100 shares of TGR’s Class B common stock, par value $0.0001 per share (the “TGR Class B common “stock”), and (ii) 2,500 shares of TGR Class A common stock, for an aggregate purchase price of $25,000. Additionally, in May 2021, TGR paid $25,000 to Kimbell Tiger Operating Company (“TGR Opco”) in exchange for the issuance of 2,500 Class A units of TGR Opco. Also in May 2021, TGR Sponsor received 100 Class A units of TGR Opco in exchange for $1,000 and 5,750,000 Class B units of TGR Opco. The shares of TGR Class B common stock and corresponding number of Class B units of TGR Opco (or the Class A units of TGR Opco into which such Class B units will convert) are collectively referred to as the “Founders Shares.” The Founders Shares will be exchangeable for shares of TGR Class A common stock upon completion of the Business Combination on a 1-for-one basis, subject to certain adjustments. Class A units and Class B units of TGR Opco are substantially similar, other than certain distribution rights, and are entitled to vote together as a single class on all matters submitted for stockholder vote.

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In determining the accounting treatment of the Partnership’s equity interest in TGR, management concluded that TGR is a VIE as defined by Accounting Standards Codification (“ASC”) Topic 810, “Consolidation.” A VIE is an entity in which equity investors at risk lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, the party who has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, as well as the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the entity. TGR Sponsor is the primary beneficiary of TGR as it has, through its equity interest, the right to receive benefits or the obligation to absorb losses from TGR, as well as the power to direct a majority of the activities that significantly impact TGR’s economic performance, including identification of a target for its Business Combination. As such, TGR is consolidated into the Partnership’s financial statements through TGR Sponsor.

Proceeds of $236.9 million were deposited in a trust account established for the benefit of TGR’s public unitholders consisting of certain proceeds from the TGR IPO and certain proceeds from the sale of the private placement warrants, net of underwriters’ discounts and commissions and other costs and expenses. A minimum balance of $236.9 million, representing the number of TGR units sold at a redemption value of $10.30 per unit, is required by the underwriting agreement to be maintained in the trust account. The proceeds held in the trust account are invested only in U.S. government treasury obligations with a maturity of 185 days or less or in money market funds meeting certain conditions under Rule 2a-7 under the Investment Company Act that invest only in direct U.S. government treasury obligations. In connection with the trust account, the Partnership reported investments held in trust of $237.0 million on the accompanying unaudited interim consolidated balance sheet at March 31, 2022.

The public unitholders’ ownership of TGR Class A common stock represents a redeemable non-controlling interest to the Partnership, which is classified outside of permanent unitholders’ equity as the TGR Class A common stock is redeemable at the option of the public unitholders in connection with the Business Combination. The carrying amount of the redeemable non-controlling interest is equal to the greater of (i) the initial carrying amount, increased or decreased for the redeemable non-controlling interest’s share of TGR’s net income or loss and distributions or (ii) the redemption value. The public unitholders of TGR Class A common stock will be entitled in certain circumstances to redeem their shares of TGR Class A common stock for a pro rata portion of the amount in the trust account at $10.30 per share of TGR Class A common stock held, plus any pro rata interest earned on the funds held in the trust account. As of March 31, 2022, the carrying amount of the redeemable non-controlling interest was recorded at its redemption value of $236.9 million. Remeasurements to the redemption value of the redeemable non-controlling interest are recognized as a deemed dividend and are recorded directly to unitholders’ equity on the accompanying unaudited interim consolidated balance sheets.

If TGR has not completed the Business Combination within such 15-month period (or 18-month or 21-month period, as applicable, if TGR Sponsor exercises its extension options), TGR will: (1) cease all operations except for the purpose of winding up; (2) as promptly as reasonably possible but not more than 10 business days thereafter, redeem the public shares, at a per-share price, payable in cash, equal to the aggregate amount then on deposit in the trust account, including interest (less an amount required to satisfy taxes of TGR and TGR Opco and up to $100,000 of interest to pay dissolution expenses), divided by the number of then outstanding public shares and TGR Class A units of Opco (other than those held by TGR), which redemption will completely extinguish public stockholders’ rights as stockholders (including the right to receive further liquidating distributions, if any); and (3) as promptly as reasonably possible following such redemption, subject to the approval of our remaining stockholders and our Board, dissolve and liquidate, subject in each case to our obligations under Delaware law to provide for claims of creditors and the requirements of other applicable law. There will be no redemption rights or liquidating distributions with respect to TGR’s warrants, which will expire worthless if TGR fails to complete the Business Combination within such 15-month period (or 18-month or 21-month period, as applicable, if the TGR Sponsor exercises its extension options).

As of March 31, 2022, the Partnership owned approximately 20% of the common stock of TGR and the net loss and net assets of TGR were consolidated with the Partnership’s financial statements. The remaining approximately 80% of the consolidated net loss and net assets of TGR, representing the percentage of economic interest in TGR held by public shareholders of TGR through their ownership of TGR common stock, were allocated to redeemable non-controlling interest. The total assets of TGR are $240.4 million and total liabilities are $8.6 million as of March 31, 2022. The assets of TGR held outside of trust can only be used to settle obligations of TGR and there is no recourse to the Partnership for TGR’s liabilities. All warrants and TGR Class B common stock held by the Partnership are eliminated in consolidations. Also, all transactions between TGR and the Partnership, as well as related financial statement impacts, eliminate in consolidation.

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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 March 31, ~~2021,~~2022, 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 percent of its enterprise value. As of March 31, ~~2021,~~2022, these economic hedges constituted approximately ~~34%~~29% of daily oil and natural gas production.

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

Interest Rate Swaps

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 ~~89%~~66% of our outstanding balance as of March 31, ~~2021)~~2022), 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 accompanying unaudited interim ~~condensed~~ consolidated statements of operations. As of March 31, ~~2021,~~2022, the interest rate swap had a total notional amount of $150.0 million and a fair value of ~~$0.5~~$5.6 million.

712

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. Changes in fair value consisted of the following:


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
Beginning fair value of derivative instruments	$	(6,280,863)	$	804,501	$	(26,624,646)	$	(6,280,863)
(Loss) gain on derivative instruments		(13,672,957)		10,132,613
Net cash paid (received) on settlements of derivative instruments		998,785		(1,153,752)
Loss on derivative instruments						(28,238,415)		(13,672,957)
Net cash paid on settlements of derivative instruments						9,557,420		998,785
Ending fair value of derivative instruments	$	(18,955,035)	$	9,783,362	$	(45,305,641)	$	(18,955,035)

The following table presents the fair value of the Partnership’s derivative contracts for the periods indicated:


		March 31,		December 31,			March 31,		December 31,
Classification	Balance Sheet Location	2021		2020		Balance Sheet Location	2022		2021
Assets:
Current assets						Derivative assets	$	2,102,159	$	166,307
Long-term assets	Derivative assets	$	697,068	$	—	Derivative assets		3,457,466		1,590,501
Liabilities:
Current liabilities	Derivative liabilities		(11,112,053)		(3,113,178)	Derivative liabilities		(43,316,700)		(24,190,678)
Long-term liabilities	Derivative liabilities		(8,540,050)		(3,167,685)	Derivative liabilities		(7,548,566)		(4,190,776)
		$	(18,955,035)	$	(6,280,863)		$	(45,305,641)	$	(26,624,646)

As of March 31, ~~2021,~~2022, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps


	Notional	Weighted Average		Range (per Bbl)				Notional	Weighted Average			Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High		Volumes (Bbl)	Fixed Price (per Bbl)			Low		High
March 2021 - December 2021	448,902	$	44.23	$	34.95	$	56.10
January 2022 - December 2022	500,552	$	41.86	$	35.65	$	46.00
January 2023 - March 2023	91,854	$	53.38	$	53.38	$	53.38
April 2022 - December 2022								368,522	$	43.69		$	41.77	$	46.00
January 2023 - December 2023								303,411	$	59.35	��	$	53.38	$	63.00
January 2024 - March 2024								54,509	$	76.32		$	76.32	$	76.32

Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)				Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High		Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
April 2021 - December 2021	5,188,150	$	2.45	$	2.33	$	2.58
January 2022 - December 2022	6,357,449	$	2.46	$	2.23	$	2.70
January 2023 - March 2023	1,204,308	$	2.73	$	2.73	$	2.73
April 2022 - December 2022								4,659,509	$	2.41	$	2.23	$	2.58
January 2023 - December 2023								4,245,899	$	2.90	$	2.52	$	3.28
January 2024 - March 2024								823,186	$	4.15	$	4.15	$	4.15

NOTE 5—FAIR VALUE MEASUREMENTS

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the unaudited interim ~~condensed~~ consolidated balance sheets approximated fair value as of March 31, ~~2021~~2022 and December 31, ~~2020~~2021 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below.

●

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

●

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

●

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

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three months ended March 31, ~~2021~~2022 and ~~2020.~~2021.

The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy. 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 recurring basis by the fair value hierarchy:


	Fair Value Measurements Using										Fair Value Measurements Using
	Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total		Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total
March 31, 2021
March 31, 2022																			��
Assets
Interest rate swap contracts											$	—	$	5,559,625	$	—	$	—	$	5,559,625
Investments held in trust											$	237,001,386	$	—	$	—	$	—	$	237,001,386
Liabilities
Commodity derivative contracts											$	—	$	(50,865,266)	$	—	$	—	$	(50,865,266)
December 31, 2021
Assets
Interest rate swap contracts	$	—	$	697,068	$	—	$	—	$	697,068	$	—	$	1,756,808	$	—	$	—	$	1,756,808
Liabilities
Commodity derivative contracts	$	—	$	(19,447,304)	$	—	$	—	$	(19,447,304)	$	—	$	(28,381,454)	$	—	$	—	$	(28,381,454)
Interest rate swap contracts	$	—	$	(204,799)	$	—	$	—	$	(204,799)
December 31, 2020
Liabilities
Commodity derivative contracts	$	—	$	(6,280,863)	$	—	$	—	$	(6,280,863)

NOTE 6—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:


	March 31,		December 31,		March 31,		December 31,
	2021		2020		2022		2021
Oil and natural gas properties
Proved properties	$	941,430,320	$	923,413,606	$	1,070,219,297	$	1,051,111,311
Unevaluated properties		208,157,655		225,681,626		134,586,442		153,284,173
Less: accumulated depreciation, depletion and impairment		(635,786,468)		(628,102,279)		(673,991,373)		(663,603,142)
Total oil and natural gas properties	$	513,801,507	$	520,992,953	$	530,814,366	$	540,792,342

The Partnership assesses all unevaluated properties on a periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market ~~conditions;~~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 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 first quarter of 2020 as a result of this impairment assessment. The transfer resulted in an additional ceiling test impairment expense for the three months ended March 31, 2020 equal to the amount of the transfer.

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

After evaluating certain external factors, in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated proved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of the development of the ~~PUD~~proved undeveloped (“PUD”) reserves and, therefore ~~recorded an impairment on such properties for the three months ended March 31, 2020. The Partnership~~ did not book PUD reserves in its total estimated proved reserves as of March 31, 2022 or December 31, ~~2020~~2021 and it does not intend to book PUD reserves going forward.

The Partnership did 0t record an impairment on its oil and natural gas properties for either of the ~~three months~~three-month periods ended March 31, ~~2021. The Partnership recorded an impairment on its oil and natural gas properties of $70.9 million for the three months ended~~2022 or March 31, ~~2020, which can primarily be attributed to factors mentioned above.~~2021.

NOTE 7—LEASES

Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying unaudited interim ~~condensed~~ consolidated balance sheets. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of March 31, ~~2021~~2022 is ~~8.08~~7.10 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the three months ended March 31, ~~2021.~~2022.

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 months ended March 31, ~~2021~~2022 and ~~2020.~~2021. The total operating lease expense recorded for both the three months ended March 31, ~~2021~~2022 and ~~2020~~2021 was $0.1 ~~million, respectively.~~million.

Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations.

Future minimum lease commitments as of March 31, ~~2021~~2022 were as follows:


	Total		2021		2022		2023		2024		2025		Thereafter		Total		2022		2023		2024		2025		2026		Thereafter
Operating leases	$	4,050,131	$	363,626	$	486,045	$	487,787	$	488,725	$	497,033	$	1,726,915	$	3,565,096	$	364,636	$	487,787	$	488,725	$	497,033	$	507,648	$	1,219,267
Less: Imputed Interest		(973,300)														(775,097)
Total	$	3,076,831													$	2,789,999

NOTE 8—LONG-TERM DEBT

On January 11, 2017, the Partnership entered into a 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

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

~~(the~~ (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 from $225.0 million to $265.0 million, the availability of 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, (ii) extend the maturity date under the 2018 Amended Credit Agreement from February 8, 2022 to June 7, 2024, (iii) reflect

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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). We are obligated to pay a quarterly commitment fee of 0.50% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing based. 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 redetermined semi-annually on or about May 1 and 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 Partnership’s wholly owned subsidiaries. In connection with the November 1, 2021 redetermination under the secured revolving credit facility, the borrowing base was increased to $275.0 million. The May borrowing base redetermination is currently being conducted and is expected to be finalized by the end of May ~~2021.~~2022.

The 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 representing limited partner interests in the Partnership (“common units”) and common units of the Operating Company (“OpCo common ~~units,~~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 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 Amended Credit Agreement) of not more than 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 Amended Credit Agreement also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change of control.

During the three months ended March 31, ~~2021,~~2022, the Partnership borrowed an additional ~~$0.5~~$19.1 million under the secured revolving credit facility and repaid approximately ~~$3.5~~$9.7 million of the outstanding borrowings. As of March 31, ~~2021,~~2022, the Partnership’s outstanding balance was ~~$168.5~~$226.5 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of March 31, ~~2021.~~2022.

As of March 31, ~~2021,~~2022, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of ~~3.50%~~3.75% or the ABR (as defined in the Amended Credit Agreement) plus a margin of ~~2.50%~~2.75%. For the three months ended March 31, ~~2021,~~2022, the weighted average interest rate on the Partnership’s outstanding borrowings was ~~3.75%~~4.10%.

~~Table~~The 1-week and 2-month U.S. dollar LIBOR settings ceased to be published after December 31, 2021 and the U.K. Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S. dollar settings after June 30, 2023. The Partnership’s secured revolving credit facility has the option of ~~Contents~~using the 1-month, 3-month or 6-month LIBOR setting and includes provisions to determine a replacement rate for LIBOR if necessary during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York. The Partnership currently do not expect the transition from LIBOR to have a material impact on them.

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

NOTE 9—PREFERRED UNITS

In July 2018, the Partnership completed the private placement of 110,000 Series A preferred units (the “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~~

Table 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 the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units.Contents

The Series A preferred units are convertible by the Series A Purchasers after two years at a 30% discount to the issue price, subject to certain conditions. The Partnership may redeem the Series A preferred units at any time. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to ~~1.2~~ ~~times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.~~

~~For purposes of the~~ ~~Series A preferred units~~, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the July 12, 2018 (the “Series A Issuance Date”), a 13.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary of the Series A Issuance Date, a 14.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the Series A Issuance Date, a 15.0% internal rate of return with respect to the Series A preferred units.

On February 12, 2020, the Partnership completed the redemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than 50% of the carrying value of the Series A preferred units as of the redemption date and 50% of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $5.7 million was recognized in unitholders’ equity and non-controlling interest during the ~~three months~~year ended ~~March~~December 31, 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 ~~following table summarizes~~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 ~~changes in~~consideration transferred by the ~~number~~Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred ~~units:~~units as of the redemption date and the redeemed portion 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 year ended December 31, 2021.

On December 7, 2021, the Partnership completed the redemption of the remaining 25,000 Series A preferred units. The Series A preferred units were redeemed at a price of $1,240.25 per Series A preferred unit for an aggregate redemption price of $31.0 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date and the remaining intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $3.6 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2021.

As of December 31, 2021 and March 31, 2022, 0 preferred units remain outstanding.
		~~Series A~~
		~~Preferred Units~~
~~Balance at December 31, 2020~~		~~55,000~~
~~Balance at March 31, 2021~~		~~55,000~~

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of March 31, ~~2021,~~2022, the Partnership had a total of ~~39,769,896~~57,290,923 common units issued and outstanding and ~~20,779,781~~8,253,660 Class B units outstanding.

In ~~January 2020,~~November 2021, the Partnership completed an underwritten public offering of ~~5,000,000~~4,312,500 common units for net proceeds of approximately ~~$73.6~~$57.7 million (the ~~“2020~~“2021 Equity Offering”). The Partnership used the net proceeds from the ~~2020~~2021 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately ~~$70.0~~$56.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. In connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units pursuant to the exercise of the underwriters’ option to purchase additional common units. The Partnership did not receive any proceeds from the sale of the common units by the selling unitholders.

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

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


		Common Units
Balance at December 31, ~~2020~~2021		~~38,918,689~~47,162,773
Conversion of Class B units		9,357,919
Common units issued under the LTIP (1)		~~936,567~~963,835
Restricted units repurchased for tax withholding		~~(85,360)~~(193,604)
Balance at March 31, ~~2021~~2022		~~39,769,896~~57,290,923

(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.~~24, 2022.

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The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the periods presented:

Amount per

Date

Unitholder

Payment

Amount per

Date

Unitholder

Payment

Common Unit

Declared

Record Date

Date

Common Unit

Declared

Record Date

Date

Q1 2022

0.47

April 22, 2022

May 2, 2022

May 9, 2022

Q1 2021

0.27

April 23, 2021

May 3, 2021

May 10, 2021

0.27

April 23, 2021

May 3, 2021

May 10, 2021

Q1 2020

0.17

April 24, 2020

May 4, 2020

May 11, 2020

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


		Class B Units
Balance at December 31, ~~2020~~2021		~~20,779,781~~17,611,579
Conversion of Class B units		(9,357,919)
Balance at March 31, ~~2021~~2022		~~20,779,781~~8,253,660

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

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

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

Basic ~~loss~~earnings (loss) per common unit is calculated by dividing net ~~loss~~income (loss) attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net ~~loss~~income (loss) per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s LTIP for its employees, directors and consultants and potential conversion of Class B units.

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
Net loss attributable to common units	$	(704,375)	$	(39,301,034)
Net income (loss) attributable to common units of Kimbell Royalty Partners, LP					$	7,330,957	$	(704,375)
Accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation						(16,325,799)		—
Net loss attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation						(8,994,842)		(704,375)

Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interests in OpCo						—		—
Accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation						—		—
Diluted net loss attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable noncontrolling interest in Kimbell Tiger Acquisition Corporation						(8,994,842)		(704,375)


Weighted average number of common units outstanding:
Basic		37,693,469		30,528,819		45,942,829		37,693,469
Effect of dilutive securities:
Series A preferred units		—		—		—		—
Class B units		—		—		—		—
Restricted units		—		—		—		—
Diluted		37,693,469		30,528,819		45,942,829		37,693,469

Net loss attributable to common units
Net loss per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	(0.02)	$	(1.29)	$	(0.20)	$	(0.02)
Diluted	$	(0.02)	$	(1.29)	$	(0.20)	$	(0.02)

The calculation of diluted net loss per share for the three months ended March 31, 2022 excludes the conversion of Class B units to common units and 1,753,986 units of unvested restricted units because their inclusion in the calculation would be anti-dilutive. The calculation of diluted net loss per unit for the three months ended March 31, 2021 ~~and 2020~~ excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 1,900,878 ~~and 1,686,117 shares~~ of unvested restricted units ~~respectively,~~ because their inclusion in the calculation would be anti-dilutive.

NOTE 12—UNIT-BASED COMPENSATION

The Partnership’s LTIP authorizes grants of up to 4,541,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued under the Partnership’s LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants is treated in the same manner as that of the employees and directors.

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


		Weighted		Weighted		Weighted		Weighted
		Average		Average		Average		Average
		Grant-Date		Remaining		Grant-Date		Remaining
		Fair Value		Contractual		Fair Value		Contractual
	Units	per Unit		Term	Units	per Unit		Term
Unvested at December 31, 2020	1,276,546	$	13.604	1.788 years
Unvested at December 31, 2021					1,560,899	$	11.108	1.775 years
Awarded	936,567		10.350	—	963,835		15.820	—
Vested	(312,235)		11.540	—	(626,371)		10.944	—
Unvested at March 31, 2021	1,900,878	$	12.340	2.161 years
Unvested at March 31, 2022					1,898,363	$	13.554	2.271 years

NOTE 13—RELATED PARTY TRANSACTIONS

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

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~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

Partnership’s Sponsors may identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution on common units to the Partnership’s unitholders.

During the three months ended March 31, ~~2021, the Partnership acquired certain assets managed by Nail Bay Royalties~~2022 and ~~Duncan Management. See Note 3—Acquisitions and Joint Ventures for further detail.~~

~~During the three months ended~~ March 31, 2021, 0 monthly services fee was paid to BJF Royalties. During the three months ended March 31, 2022, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $30,000, $41,251 and $75,090, respectively. During the three months ended March 31, 2021, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $30,000, $75,329 and $137,120, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s LTIP.

~~NOTE 14—ADMINISTRATIVE SERVICES~~

~~Management Services Agreement~~

~~The~~Commencing on the date of the TGR IPO, TGR agreed to pay the Partnership ~~relies upon its officers, directors, Sponsors~~a total of $25,000 per month for office space utilities, secretarial support and ~~outside consultants~~administrative services provided to further its business operations. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. See Note 13―Related Party Transactions.members of the management team. Upon completion of TGR’s initial Business Combination or TGR’s liquidation, TGR will cease paying these monthly fees. During the three months ended March 31, 2022, TGR incurred $43,750 as part of this service agreement.

NOTE ~~15—~~14—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity as of March 31, ~~2021.~~2022.

NOTE ~~16—~~15—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to March 31, ~~2021~~2022 in the preparation of its unaudited interim ~~condensed~~ consolidated financial statements.

Debt

On April ~~27, 2021~~29, 2022, the Partnership drew down ~~$4.0~~$17.1 million on the senior secured revolving credit facility to fund certain operational expenses.

Distributions

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On May ~~4, 2021, the Partnership paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended March 31, 2021.~~

~~On May 5, 2021,~~6, 2022, the Partnership paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of ~~$20,780 for the quarter ended March 31, 2021.~~$8,211.

On April ~~23, 2021,~~22, 2022, the Board of Directors declared a quarterly cash distribution of ~~$0.27~~$0.47 per common unit for the quarter ended March 31, ~~2021.~~2022. The distribution ~~will be~~was paid on May ~~10, 2021~~9, 2022 to common unitholders and OpCo common unitholders of record as of the close of business on May ~~3, 2021.~~2, 2022.

Conversion of Class B units to common units

On April 22, 2022, certain holders of Class B units converted 42,081 Class B units to common units. In connection with this conversion, the 5 cents per Class B unit consideration paid by the Class B unitholders to the Partnership was repaid to the Class B unitholders on April 26, 2022.

Divestitures

On April 29, 2022, the Joint Venture completed the sale of all of its royalty, mineral and overriding interests and similar non-cost bearing interests in oil and gas properties for a total purchase price of $14.8 million. Net proceeds realized by the Partnership were $6.4 million.

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

The following discussion and analysis of financial condition and results of operations should be read ~~together~~ in conjunction with our unaudited interim ~~condensed~~ consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021 (the ~~“2020~~“2021 Form 10-K”).

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” the “Partnership,” “we” or “us” refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. References to the “Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership.

Cautionary Statement Regarding Forward-Looking Statements

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

●

our ability to replace our reserves;

●

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

●

our ability to execute our business strategies;

●

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

●

industry, economic, business or 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;

●

the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine;

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●

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 generally and the mineral and royalty industry in particular;

●

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

●

title defects in the properties in which we acquire an interest;

●

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, 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;

●

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

●

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

●

the ability of Kimbell Tiger Acquisition Corporation (“TGR”) to select an appropriate target business or businesses, enter into a binding agreement with a target and complete its initial business combination, as well as its ability to obtain necessary financing to complete its initial business combination; and

●

the overall performance and success of any target business or businesses selected by TGR for its initial business combination.

These factors are discussed in further detail in the ~~2020~~2021 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 made, whether as a result of new information, future events or otherwise. All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

Overview

We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, we have elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. Our primary business

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objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of March 31, ~~2021,~~2022, we owned mineral and royalty interests in approximately ~~9.1~~11.4 million gross acres and overriding royalty interests in approximately ~~4.6~~4.7 million gross acres, with approximately ~~60%~~62% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of March 31, ~~2021,~~2022, over ~~98%~~99% 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 28 states and in

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every major onshore basin across the continental United States and include ownership in over ~~97,000~~122,000 gross wells, including over ~~41,000~~46,000 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 March 31, ~~2021:~~2022:


			Average Daily	Average Daily				Average Daily
			Production	Production				Production
Basin or Producing Region	Gross Acreage	Net Acreage	(Boe/d)(6:1)(1)	(Boe/d)(20:1)(2)	Well Count	Gross Acreage	Net Acreage	(Boe/d)(6:1)(1)	Well Count
Permian Basin	2,662,777	23,075	2,576	2,079	41,075	2,935,371	23,560	2,451	46,933
Mid‑Continent	3,955,148	41,402	1,545	919	11,267	5,369,358	44,310	1,795	19,118
Haynesville	786,724	7,665	3,295	1,124	8,861	1,428,907	7,919	3,505	16,065
Appalachia	741,354	23,202	2,040	825	3,208	741,354	23,203	1,987	3,818
Bakken	1,569,637	6,051	718	603	4,124	1,640,077	6,138	978	5,180
Eagle Ford	624,148	6,730	1,551	1,223	3,235	624,148	6,730	1,565	3,930
Rockies	74,152	1,036	729	405	12,359	74,152	1,036	909	12,502
Other	3,232,561	36,694	1,267	709	13,028	3,232,561	36,693	1,292	15,353
Total	13,646,501	145,855	13,721	7,887	97,157	16,045,928	149,589	14,482	122,899

(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~~2021 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 March 31, ~~2021:~~2022:


Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	308	258	0.68	0.74	260	312	0.53	0.86
Mid‑Continent	102	65	0.34	0.08	116	71	0.26	0.09
Haynesville	65	31	0.35	0.04	95	35	0.73	0.16
Appalachia	19	36	0.06	0.12	12	42	0.05	0.14
Bakken	154	174	0.25	0.71	141	140	0.17	0.74
Eagle Ford	61	73	0.45	0.56	76	55	0.50	0.61
Rockies	52	32	0.07	0.29	5	28	0.01	0.18
Total	761	669	2.20	2.54	705	683	2.25	2.78

(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

Initial Public Offering of Kimbell Tiger Acquisition Corporation

On July 29, 2021, TGR, the Partnership’s newly formed special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the SEC. On February 8, 2022, TGR consummated its initial public offering (the “TGR IPO”) of 23,000,000 units (each a “unit” and, collectively, the “units”), including 3,000,000 additional units issued pursuant to the underwriter’s exercise in full of its over-allotment option, at $10.00 per unit, generating proceeds of

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~~The following table summarizes estimates~~approximately $230.0 million and incurring offering costs of approximately $12.7 million, inclusive of $8.1 million in deferred underwriting commissions. Each unit consists of one share of Class A common stock and one-half of one redeemable warrant. Each whole warrant may be exercised for one share of Class A common stock at a price of $11.50 per share. Certain members of our ~~remaining horizontal drilling inventory~~management and members of the Board of Directors are members of the sponsor of TGR. TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses (the “Business Combination”). Under the terms of TGR’s governing documents, TGR has 15 months (or up to 21 months under certain circumstances) from the closing of the TGR IPO to complete the Business Combination.

In connection with the closing of the TGR IPO, TGR completed the sale of 14.1 million private placement warrants (the “private placement warrants”) to TGR Sponsor for a purchase price of $1.00 per private placement warrant, generating gross proceeds of $14.1 million. Each private placement warrant is exercisable to purchase for $11.50 one share of TGR Class A common stock.

In May 2021, prior to the TGR IPO, TGR Sponsor paid $25,000 in exchange for the issuance of (i) 5,750,100 shares of TGR’s Class B common stock, par value $0.0001 per share (the “TGR Class B common stock”), and (ii) 2,500 shares of TGR’s Class A common stock, par value $0.0001 (the “TGR Class A common stock, for an aggregate purchase price of $25,000. Additionally, in May 2021, TGR paid $25,000 to Kimbell Tiger Operating Company (“TGR Opco”) in exchange for the issuance of 2,500 Class A units of TGR Opco. Also in May 2021, TGR Sponsor received 100 Class A units of TGR Opco in exchange for $1,000 and 5,750,000 Class B units of TGR Opco. The shares of TGR Class B common stock and corresponding number of Class B units of TGR Opco (or the Class A units of TGR Opco into which such Class B units will convert) are collectively referred to as the “Founders Shares.” The Founders Shares will be exchangeable for shares of TGR Class A common stock upon completion of the Business Combination on a one-for-one basis, subject to certain adjustments. Class A units and Class B units of TGR Opco are substantially similar, other than certain distribution rights, and are entitled to vote together as a single class on all matters submitted for stockholder vote.

In determining the accounting treatment of the Partnership’s equity interest in TGR, management concluded that TGR is a variable interest entity (“VIE”) as defined by ~~basin~~Accounting Standards Codification (“ASC”) Topic 810, “Consolidation.” A VIE is an entity in which equity investors at risk lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, the party who has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, as well as the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the entity. TGR Sponsor is the primary beneficiary of TGR as it has, through its equity interest, the right to receive benefits or the obligation to absorb losses from TGR, as well as the power to direct a majority of the activities that significantly impact TGR’s economic performance, including identification of a target for its Business Combination. As such, TGR is fully consolidated into the Partnership’s financial statements.

As of March 31, ~~2021:~~

Basin or Producing Region

Gross Locations(1)

Net Locations(1)

Average Gross Horizontal Wells/DSU(2)
Permian Basin

3,017

19.20

12.0
Mid‑Continent

1,489

6.38

6.8
Haynesville

1,309

17.04

5.9
Appalachia

247

2.17

7.6
Bakken

2,042

4.51

8.5
Eagle Ford

1,846

17.28

6.9
Rockies

210

1.56

10.5
Total

10,160

68.14

8.3

~~(1)~~

Represents an estimated 15 years of drilling inventory based on the pace of well completions during 2019, which we believe is a more normalized level of activity compared to 2020, which was impacted by the slowdown resulting from COVID-19. These locations only include our major properties and do not include locations from our minor properties, which generally include properties with less than a 0.1% net revenue interest and are time consuming to quantify, but in the estimation of our management, could add up to an additional2022, the Partnership owned approximately 20% ~~to our net inventory in the aggregate.~~

~~(2)~~

~~Gross horizontal wells per drilling spacing unit (“DSU”) from our internal reserves database as of March 31, 2021. DSUs vary in size.~~

~~Estimates~~ of ~~drilling locations, gross horizontal wells per DSU~~the common stock of TGR and ~~years~~the net loss and net assets of ~~drilling inventory are inherently uncertain~~TGR were consolidated with the Partnership’s financial statements. The remaining approximately 80% of the consolidated net loss and ~~actual results could differ substantially from these estimates. Please read “—Cautionary Statement Regarding Forward-Looking Statements”~~net assets of TGR, representing the percentage of economic interest in TGR held by public shareholders of TGR through their ownership of TGR common stock, were allocated to redeemable non-controlling interest. All transactions between TGR and ~~“Risk Factors” elsewhere~~TGR Sponsor, as well as related financial statement impacts, eliminate in ~~this report.~~

~~Recent Developments~~

~~Debt~~

~~On April 27, 2021 we drew down $4.0 million on the senior secured revolving credit facility to fund certain operational expenses.~~consolidation.

Quarterly Distributions

~~On May 4, 2021, we paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended March 31, 2021.~~

Each holder of KRP’s 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 KRP’s Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution. On May ~~5, 2021,~~6, 2022, we paid a quarterly cash distribution to each Class B unitholder, resulting in a total quarterly distribution of ~~$20,780~~$8,211 for the quarter ended March 31, ~~2021.~~2022.

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On April ~~23, 2021,~~22, 2022, the ~~General Partner’s~~ Board of Directors ~~(the “Board of Directors”)~~ declared a quarterly cash distribution of ~~$0.27~~$0.47 per common ~~unit~~units representing limited partner interests in the Partnership (“common units”) for the quarter ended March 31, ~~2021.~~2022. The distribution ~~will be~~was paid on May ~~10, 2021~~9, 2022 to common unitholders and OpCo common unitholders of record as of the close of business on May ~~3, 2021.~~2, 2022.

Business Environment

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

~~The~~COVID-19 remains a global ~~spread of COVID-19 created significant volatility, uncertainty,~~health crisis and economic disruption during 2020 and continuing into 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 has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, our oil, natural gas, and

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NGL operators and other parties with whom we have business relations, including a significant reduction in the global demand for oil and natural gas. This significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance ledthere continues to a significantly weaker outlook for oil and gas producers and is 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 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 office.

~~There is~~ considerable uncertainty regarding the extent to which COVID-19 and its variants will continue to ~~spread~~spread. Despite improvements in global economic activity levels and higher energy demand compared to 2021, the impacts of COVID-19 continue to be unpredictable, including the impacts of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. The Partnership is unable to reasonably estimate the period of time that related conditions could exist or the extent ~~and duration~~to which they could impact the Partnership’s business, results 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 the first quarter of 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 has had disruptive impacts on the oil and natural gas exploration and production industry and on other related industries. These industry conditions, coupled with those resulting from the COVID-19 pandemic, has led to significant global economic contraction generally and in our industry in particular.

~~Oil and natural gas~~operations, financial condition or cash flows. Commodity prices have ~~historically been volatile;~~risen from 2021; however, further negative impacts from COVID-19 may require the volatility in the prices for these commodities substantially increased as a result of COVID-19, the OPEC announcements mentioned above and ongoing storage capacity concerns. Oil prices declined sharply in April 2020. Although strip pricing for natural gas has increased meaningfully, the impact of these recent developments on ourPartnership to adjust its business and the oil and gas industry is unpredictable. We derived approximately 41% of our revenues and 61% of our production on a Boe/d basis (6:1) from natural gas for the first quarter of 2021, which we believe presents some downside protection against depressed oil prices.

In April 2020, we received notices from two operators regarding well shut-ins and curtailments of production on properties in which we own an interest. The properties were primarily located in the Eagle Ford Shale, and the production attributable to such properties on a Boe/d basis (6:1) represented approximately one percent of our total production for the first quarter of 2020. We received subsequent notice that the curtailment on all Eagle Ford Shale production ceased and production resumed, effective June 1, 2020. We also received notifications of well shut-ins and curtailment in the second quarter of 2020 from additional operators and the production attributable to such properties on a Boe/d basis (6:1) accounted for less than one percent of our total production for the second quarter of 2020. We did not receive any notification of shut-ins or curtailment in the second half of 2020. While we currently do not expect we will receive additional notices, we cannot predict whether additional shut-ins and curtailments of production from our operators will occur if oil and natural gas prices decline or reductions in global demand and storage capacity issues continue or worsen.plan.

The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on ~~our~~the Partnership’s business, cash flows, liquidity, financial condition and results of operations ~~will depend~~remain dependent on a number of factors, ~~including, among others,~~such as the ~~ultimate severity of COVID-19, the consequences of governmental~~duration and ~~other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration~~scope of the pandemic, ~~actions taken by members~~the length and severity of the worldwide economic downturn, the ability of OPEC, Russia and other ~~foreign, oil-exporting countries, governmental authorities~~crude oil producing nations to manage the global crude oil supply, additional actions by businesses and ~~other third parties, workforce availability,~~governments in response to the pandemic, the economic downturn and the ~~timing~~decrease in crude oil demand, the speed and ~~extent~~effectiveness of ~~any return~~responses to ~~normal economic~~combat the virus and ~~operating~~

~~Table~~the time necessary to balance crude oil supply and demand to restore crude oil pricing. Although prices have recovered, the ongoing impact of ~~Contents~~

~~conditions.~~COVID-19 on our business, employees and operations, including supply chain concerns, among others still continues to affect our industry. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in Part I, Item 1A. Risk Factors in our ~~2020~~2021 Form 10-K.

Russia / Ukraine Conflict

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from the COVID-19 outbreak and various OPEC announcements, ~~along with~~ the winter storms experienced in parts of the United States in February 2021 and the current conflict between Russia and Ukraine have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (“EIA”).


	Three Months Ended March 31, 2021				Three Months Ended March 31, 2020				Three Months Ended March 31, 2022				Three Months Ended March 31, 2021
	High		Low		High		Low		High		Low		High		Low
Oil ($/Bbl)	$	66.08	$	47.47	$	63.27	$	14.10	$	123.64	$	75.99	$	66.08	$	47.47
Natural gas ($/MMBtu)	$	23.86	$	2.45	$	2.17	$	1.65	$	6.70	$	3.73	$	23.86	$	2.45

On April ~~30, 2021,~~29, 2022, the West Texas Intermediate posted price for crude oil was ~~$63.50~~$104.59 per Bbl and the Henry Hub spot market price of natural gas was ~~$2.86~~$6.84 per MMBtu.

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The following table, as reported by the EIA, sets forth the average daily prices for oil and natural gas.


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
Oil ($/Bbl)	$	58.09	$	45.54	$	95.18	$	58.09
Natural gas ($/MMBtu)	$	3.50	$	1.90	$	4.67	$	3.50

Rig Count

Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The Baker Hughes United States Rotary Rig count ~~decreased by 41.4% from 710~~increased significantly to 657 active land rigs at March 31, ~~2020~~2022 compared to 416 active land rigs at March 31, 2021. The ~~416~~657 active land rigs at March 31, ~~2021~~2022 increased by ~~25.3%~~15.3% from ~~332~~570 active land rigs at December 31, ~~2020.~~

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According to the Baker Hughes United States Rotary Rig count, rig activity in the 28 states in which we own mineral and royalty interests included 413 active land rigs as of March 31, 2021 compared to 700 active land rigs as of March 31, 2020. The decrease in rig count is directly related to the COVID-19 outbreak and international supply and demand imbalances. See ~~Business Environment~~ — ~~COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas~~ ~~for further discussion. The 413 active land rig count at March 31, 2021 increased by 25.2% from 330 active land rigs at December 31, 2020.~~2021. The increase in rig count ~~from December 31, 2020,~~ is primarily attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas ~~prices.~~prices and overall supply shortages.

The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated:


	March 31,		March 31,
Basin or Producing Region	2021	2020	2022	2021
Permian Basin	23	30	32	23
Mid‑Continent	7	13	14	7
Haynesville	11	8	13	11
Appalachia	2	3	2	2
Bakken	2	11	5	2
Eagle Ford	3	8	6	3
Rockies	—	2
Other	1	—	1	1
Total	49	75	73	49

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
Royalty income
Oil sales	47	%	58	%	51	%	47	%
Natural gas sales	41	%	32	%	35	%	41	%
NGL sales	11	%	9	%	13	%	11	%
Lease bonus and other income	1	%	1	%	1	%	1	%
	100	%	100	%	100	%	100	%

We have entered into oil and natural gas commodity derivative agreements, ~~beginning January 1, 2018~~ which extend through March ~~2023,~~2024, 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.

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Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution on Common Units

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

We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, ~~non-cash unit-based~~non cash unit based compensation, ~~change in fair value of open~~unrealized gains and losses on derivative instruments, cash distribution from affiliate, ~~and~~ equity income in ~~affiliate.~~affiliate, interest income and non-recurring general and administrative expenses incurred relating to the TGR IPO. Adjusted EBITDA is not a measure of net income (loss) as determined by generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution on common units 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 on common units 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 on common units may not be comparable to other similarly titled measures of other companies.

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

Three Months Ended March 31,

2021

2020
Reconciliation of net income (loss) to Adjusted EBITDA:

Net income (loss)

$
537,194

$
(59,784,399)
Depreciation and depletion expense

7,911,148

13,270,683
Interest expense

2,095,098

1,421,304
Cash distribution from affiliate

216,738

—
Provision for income taxes

—

—
EBITDA

10,760,178

(45,092,412)
Impairment of oil and natural gas properties

—

70,925,731
Unit-based compensation

2,692,494

2,107,587
Loss (gain) on derivative instruments, net of settlements

12,674,172

(8,978,861)
Cash distribution from affiliate

55,039

17,961
Equity income in affiliate

(185,080)

(163,554)
Consolidated Adjusted EBITDA

25,996,803

18,816,452
Adjusted EBITDA attributable to noncontrolling interest

(8,921,730)

(7,059,747)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP

17,075,073

11,756,705
Adjustments to reconcile Adjusted EBITDA to cash available for distribution

Cash interest expense

1,099,087

703,952
Cash distributions on Series A preferred units

632,184

1,202,759
Restricted units repurchased for tax withholding

606,625

—
Distributions on Class B units

20,780

24,807
Cash available for distribution on common units

$
14,716,397

$
9,825,187

Three Months Ended March 31,

2021

2020
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

Net cash provided by operating activities

$
15,480,993

$
20,787,606
Interest expense

2,095,098

1,421,304
Provision for income taxes

—

—
Impairment of oil and natural gas properties

—

(70,925,731)
Amortization of right-of-use assets

(71,785)

(67,470)
Amortization of loan origination costs

(371,487)

(266,318)
Equity income in affiliate

185,080

163,554
Unit-based compensation

(2,692,494)

(2,107,587)
(Loss) gain on derivative instruments, net of settlements

(12,674,172)

8,978,861
Changes in operating assets and liabilities:

Oil, natural gas and NGL receivables

7,215,335

(4,913,049)
Accounts receivable and other current assets

583,862

508,985
Accounts payable

(153,681)

450,579
Other current liabilities

1,092,287

809,594
Operating lease liabilities

71,142

67,260
EBITDA

10,760,178

(45,092,412)
Add:

Impairment of oil and natural gas properties

—

70,925,731
Unit-based compensation

2,692,494

2,107,587
Loss (gain) on derivative instruments, net of settlements

12,674,172

(8,978,861)
Cash distribution from affiliate

55,039

17,961
Equity income in affiliate

(185,080)

(163,554)
Consolidated Adjusted EBITDA

25,996,803

18,816,452
Adjusted EBITDA attributable to noncontrolling interest

(8,921,730)

(7,059,747)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP

$
17,075,073

$
11,756,705


	Three Months Ended March 31,
	2022		2021
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:
Net income	$	8,407,244	$	537,194
Depreciation and depletion expense		10,759,164		7,911,148
Interest expense		2,877,855		2,095,098
Cash distribution from affiliate		385,326		216,738
Provision for income taxes		271,799		—
EBITDA		22,701,388		10,760,178
Unit-based compensation		2,194,342		2,692,494
Loss on derivative instruments, net of settlements		18,680,995		12,674,172
Cash distribution from affiliate		42,544		55,039
Equity income in affiliate		(249,408)		(185,080)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		(101,386)		—
Non-recurring general and administrative expenses		660,671		—
Consolidated Adjusted EBITDA		43,929,146		25,996,803
Adjusted EBITDA attributable to noncontrolling interest		(5,531,750)		(8,921,730)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		38,397,396		17,075,073
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		1,958,779		1,099,087
Cash distributions on Series A preferred units		—		632,184
Restricted units repurchased for tax withholding		—		606,625
Distributions on Class B units		17,610		20,780
Cash available for distribution on common units	$	36,421,007	$	14,716,397

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	Three Months Ended March 31,
	2022		2021
Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units:
Net cash provided by operating activities	$	36,032,473	$	15,480,993
Interest expense		2,877,855		2,095,098
Provision for income taxes		271,799		—
Amortization of right-of-use assets		(78,025)		(71,785)
Amortization of loan origination costs		(442,399)		(371,487)
Equity income in affiliate		249,408		185,080
Unit-based compensation		(2,194,342)		(2,692,494)
Loss on derivative instruments, net of settlements		(18,680,995)		(12,674,172)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		6,409,027		7,215,335
Accounts receivable and other current assets		(730,660)		583,862
Accounts payable		(1,082,653)		(153,681)
Other current liabilities		(463,173)		1,092,287
Operating lease liabilities		79,246		71,142
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		101,386		—
Other assets and liabilities		352,441		—
EBITDA		22,701,388		10,760,178
Add:
Unit-based compensation		2,194,342		2,692,494
Loss on derivative instruments, net of settlements		18,680,995		12,674,172
Cash distribution from affiliate		42,544		55,039
Equity income in affiliate		(249,408)		(185,080)
Consolidated variable interest entities related:
Interest earned on marketable securities in Trust Account		(101,386)		—
Non-recurring general and administrative expenses		660,671		—
Consolidated Adjusted EBITDA		43,929,146		25,996,803
Adjusted EBITDA attributable to noncontrolling interest		(5,531,750)		(8,921,730)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		38,397,396		17,075,073
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		1,958,779		1,099,087
Cash distributions on Series A preferred units		—		632,184
Restricted units repurchased for tax withholding		—		606,625
Distributions on Class B units		17,610		20,780
Cash available for distribution on common units	$	36,421,007	$	14,716,397

Factors Affecting the Comparability of Our Results to Our Historical Results

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

Ongoing Acquisition Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as ~~"auction"~~“auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of

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our results for the three months ended March 31, ~~2021~~2022 and ~~2020~~2021 include the acquisition of all of the equity interests in ~~Springbok Energy Partners,~~certain subsidiaries owned by Caritas Royalty Fund LLC and ~~Springbok Energy Partners II, LLC~~certain of its affiliates (the ~~“Springbok~~“Cornerstone 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 acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long-term results for some time thereafter.

Impairment of Oil and Natural Gas Properties

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

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We did not record an impairment on our oil and natural gas properties for the three months ended March 31, ~~2021. For the three months ended March 31, 2020, we recorded an impairment on our oil~~2022 and ~~natural gas properties of $70.9 million, which can primarily be attributed to the 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, 2019, as well as our unevaluated oil and natural gas properties. Specifically, with respect to our PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), we determined that we did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties for the three months ended March 31, 2020. We similarly recorded an impairment on the value of our unevaluated oil and natural gas properties for the three months ended March 31, 2020, which primarily were acquired in various acquisitions since our initial public offering.2021.

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 price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.

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Results of Operations

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	36,368,510	$	25,585,439	$	65,083,903	$	36,368,510
Lease bonus and other income		186,308		229,319		654,130		186,308
(Loss) gain on commodity derivative instruments, net		(14,135,728)		10,132,613
Loss on commodity derivative instruments, net						(31,983,520)		(14,135,728)
Total revenues		22,419,090		35,947,371		33,754,513		22,419,090
Costs and expenses
Production and ad valorem taxes		2,431,830		1,621,743		4,020,911		2,431,830
Depreciation and depletion expense		7,911,148		13,270,683		10,759,164		7,911,148
Impairment of oil and natural gas properties		—		70,925,731
Marketing and other deductions		3,295,286		2,131,552		3,508,066		3,295,286
General and administrative expenses		6,796,385		6,524,311		6,589,259		6,796,385
Consolidated variable interest entities related:
General and administrative expense						739,459		—
Total costs and expenses		20,434,649		94,474,020		25,616,859		20,434,649
Operating income (loss)		1,984,441		(58,526,649)
Operating income						8,137,654		1,984,441
Other income (expense)
Equity income in affiliate		185,080		163,554		249,408		185,080
Interest expense		(2,095,098)		(1,421,304)		(2,877,855)		(2,095,098)
Other income		462,771		—		3,068,450		462,771
Net income (loss) before income taxes		537,194		(59,784,399)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account						101,386		—
Net income before income taxes						8,679,043		537,194
Provision for income taxes		—		—		271,799		—
Net income (loss)		537,194		(59,784,399)
Net income						8,407,244		537,194
Distribution and accretion on Series A preferred units		(1,577,968)		(3,076,684)		—		(1,577,968)
Net loss attributable to noncontrolling interests		357,179		23,584,856
Net (income) loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests in OpCo						(1,058,677)		357,179
Distribution on Class B units		(20,780)		(24,807)		(17,610)		(20,780)
Net loss attributable to common units	$	(704,375)	$	(39,301,034)
Net income (loss) attributable to common units of Kimbell Royalty Partners, LP					$	7,330,957	$	(704,375)
Production Data:
Oil (Bbls)		319,649		334,149		392,361		319,649
Natural gas (Mcf)		4,500,314		4,264,345		4,835,849		4,500,314
Natural gas liquids (Bbls)		165,189		170,689		204,425		165,189
Combined volumes (Boe) (6:1)		1,234,890		1,215,562		1,402,761		1,234,890

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Comparison of the Three Months Ended March 31, ~~2021~~2022 to the Three Months Ended March 31, ~~2020~~2021

Oil, Natural Gas and NGL Revenues

For the three months ended March 31, ~~2021,~~2022, our oil, natural gas and NGL revenues were ~~$36.4~~$65.1 million, an increase of ~~$10.8~~$28.7 million from ~~$25.6~~$36.4 million for the three months ended March 31, ~~2020.~~2021. The increase 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 three months ended March 31, ~~2021~~2022 as discussed below.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,402,761 Boe or 14,482 Boe/d, for the three months ended March 31, 2022, an increase of 167,871 Boe or 761 Boe/d, from 1,234,890 Boe or 13,721 Boe/d, for the three months ended March 31, ~~2021, an increase of 19,328 Boe or 363 Boe/d, from 1,215,562 Boe or 13,358 Boe/d, for the three months ended March 31, 2020.~~2021. The increase in production for the three months ended March 31, 2022 from March 30, 2021 was primarily attributable to production associated with the ~~Springbok Acquisition, which accounted for 180,066 Boe or 2,001 Boe/d. The increase was~~assets located in the Haynesville, Mid-Continent, Bakken and Rockies basins, partially offset by a reduction in production ~~on our other assets as a result~~in the Permian basin.

Table of the COVID-19 outbreak and international supply and demand imbalances and, to a lesser extent, the 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.~~Contents

Our operators received an average of $86.08 per Bbl of oil, $4.76 per Mcf of natural gas and $40.57 per Bbl of NGL for the volumes sold during the three months ended March 31, 2022 compared to $54.52 per Bbl of oil, $3.31 per Mcf of natural gas and $24.45 per Bbl of NGL for the volumes sold during the three months ended March 31, ~~2021 compared to $45.25 per Bbl of oil, $1.93 per Mcf of natural gas and $13.17 per Bbl of NGL for the volumes sold~~2021. These average prices received during the three months ended March 31, ~~2020. The three months ended March 31, 2021~~2022 increased ~~20.5%~~57.9% or ~~$9.27~~$31.56 per Bbl of oil and ~~71.5%~~43.8% or ~~$1.38~~$1.45 per Mcf of natural gas as compared to the three months ended March 31, ~~2020.~~2021. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increases of ~~27.6%~~63.8% or ~~$12.55~~$37.09 per Bbl of oil and ~~84.2%~~33.4% or ~~$1.60~~$1.17 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income ~~remained flat at $0.2~~was $0.7 million for ~~both~~ the three months ended March 31, ~~2021~~2022 compared to $0.2 million for the three months ended March 31, 2021. The increase in lease bonus and ~~2020.~~other income is primarily related to an increase in operators’ leasing activity on our acreage, primarily in the Permian Basin, as a result of the increase in oil and natural gas prices.

~~(Loss) Gain~~Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended March 31, ~~2021~~2022 included $22.5 million of mark-to-market losses and $9.5 million of losses on the settlement of commodity derivative instruments compared to $13.2 million of mark-to-market losses and $1.0 million of losses on the settlement of commodity derivative instruments ~~compared to $9.0 million of mark-to-market gains and $1.1 million of gains on the settlement of commodity derivative instruments~~ for the three months ended March 31, ~~2020.~~2021. We recorded a mark-to-market loss for the three months ended March 31, 2022 as a result of the increase in the strip pricing of oil and natural gas from the three months ended December 31, 2021 to the three months ended March 31, 2022. We recorded a mark-to-market loss for the three months ended March 31, 2021 as a result of the increase in the strip pricing of oil and natural gas from the three months ended December 31, 2020 to the three months ended March 31, 2021. The mark-to-market gain recorded for the three months ended March 31, 2020 was due to the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended March 31, ~~2021~~2022 were ~~$2.4~~$4.0 million, an increase of ~~$0.8~~$1.6 million from ~~$1.6~~$2.4 million for the three months ended March 31, ~~2020.~~2021. The increase in production and ad valorem taxes was primarily ~~attributable~~related to the ~~Springbok Acquisition and the~~significant increase in the average prices we received for oil, natural gas and NGL production for the three months ended March 31, ~~2021.~~2022 and the Cornerstone Acquisition.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended March 31, ~~2021~~2022 was ~~$7.9~~$10.8 million, ~~a decrease~~an increase of ~~$5.4~~$2.9 million from ~~$13.3~~$7.9 million for the three months ended March 31, ~~2020.~~2021. The ~~decrease~~increase in depreciation and depletion expense was due to ~~the impairment that was recorded during the year ended December 31, 2020,~~Cornerstone Acquisition, which significantly ~~reduced~~increased our net capitalized oil and natural gas properties.

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Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was ~~$6.22~~$7.41 for the three months ended March 31, ~~2021, a decrease~~2022, an increase of ~~$4.64~~$1.19 per barrel from the ~~$10.86~~$6.22 average depletion rate per barrel for the three months ended March 31, ~~2020.~~2021. The ~~decrease~~increase in the depletion rate was due to the ~~significant impairment~~Cornerstone Acquisition that was ~~recorded during the year ended~~closed in December ~~31, 2020,~~2021 which significantly ~~reduced~~increased our net capitalized oil and natural gas properties.

~~Impairment of Oil, Natural Gas and Natural Gas Liquids Expense~~

We did not record an impairment expense on our oil and natural gas properties for the three months ended March 31, 2021. We recorded an impairment expense on our oil and natural gas properties of $70.9 million during the three months ended March 31, 2020. The impairment recorded during the three months ended March 31, 2020 was due to a significant decline in the trailing twelve month average of oil and natural gas prices, related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended March 31, ~~2021~~2022 were ~~$3.3~~$3.5 million, an increase of ~~$1.2~~$0.2 million from ~~$2.1~~$3.3 million for the three months ended March 31, ~~2020, which~~2021. The increase in marketing and other deductions was primarily ~~attributable~~related to the ~~Springbok~~significant increase in the average prices we received for oil, natural gas and NGL production for the three months ended March 31, 2022 and the Cornerstone Acquisition.

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General and Administrative Expenses

General and administrative expenses for the three months ended March 31, ~~2021~~2022 were ~~$6.8~~$7.3 million, an increase of ~~$0.3~~$0.5 million from ~~$6.5~~$6.8 million for the three months ended March 31, ~~2020.~~2021. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable to ~~a $0.6~~$0.7 million ~~increase in unit-based compensation expense, which was~~of general and administrative expenses incurred by TGR, partially offset by a ~~$0.3~~$0.5 million decrease in ~~cash general and administrative expenses.~~unit-based compensation expense.

Interest Expense

Interest expense for the three months ended March 31, ~~2021~~2022 was ~~$2.1~~$2.9 million compared to ~~$1.4~~$2.1 million for the three months ended March 31, ~~2020.~~2021. The increase in interest expense was primarily due to debt incurred in 2021 to fund the ~~Springbok Acquisition. The increase in interest expense was partially offset by~~redemption of the ~~decline in the weighted average interest rate from 4.70% during the three months ended March 31, 2020 to 3.75% during the three months ended March 31, 2021.~~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. See “Indebtedness” below for further discussion of our secured revolving credit facility.

Cash Distribution Policy

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in the limited liability company agreement of the Operating Company

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and our partnership agreement. We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

In light of the unprecedented global economic impact resulting from the COVID-19 pandemic, the related impact to the United States oil and natural gas markets and the potential for further curtailments of production, the Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the first quarter of ~~2021~~2022 for the repayment of ~~$5.6~~$10.4 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the first quarter of ~~2021.~~2022. 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 may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the 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 quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. ~~For example, we 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 Board of Directors may choose to reserve a portion of cash generated from

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operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Quarterly Distributions” above for discussion of our first quarter ~~2021~~2022 distributions.

Cash Flows

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


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
Cash Flow Data:
Net cash provided by operating activities	$	15,480,993	$	20,787,606	$	36,032,473	$	15,480,993
Net cash used in investing activities		(811,651)		(11,176,643)		(237,311,341)		(811,651)
Net cash used in financing activities		(16,349,984)		(9,334,346)
Net (decrease) increase in cash and cash equivalents	$	(1,680,642)	$	276,617
Net cash provided by (used in) financing activities						207,768,223		(16,349,984)
Net increase (decrease) in cash and cash equivalents					$	6,489,355	$	(1,680,642)

Operating Activities

Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the three months ended March 31, ~~2021~~2022 were ~~$15.5~~$36.0 million, ~~a decrease~~an increase of ~~$5.3~~$20.5 million compared to ~~$20.8~~$15.5 million for the three months ended March 31, ~~2020.~~2021. The increase in cash flows provided by operating activities was primarily attributable to the increase in the average prices we received for oil, natural gas and NGL production for the three months ended March 31, 2022.

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Investing Activities

Cash flows used in investing activities for the three months ended March 31, ~~2021 decreased by $10.4~~2022 were $237.3 million compared to $0.8 million for the three months ended March 31, ~~2020.~~2021. For the three months ended March 31, 2022, cash flows used in investing activities include $236.9 million of investments held in marketable securities related to TGR and $0.4 million used to fund costs associated with the Cornerstone Acquisition. For the three months ended March 31, 2021, we used $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”)~~ and $0.4 million primarily to fund the renovation of office, partially offset by a $0.05 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 three months ended March 31, 2020, we used $9.7 million to fund the deposit on oil and natural gas properties and $1.3 million to fund capital commitments of the Joint Venture.~~

Financing Activities

Cash flows ~~used in~~provided by financing activities were ~~$16.3~~$207.8 million for the three months ended March 31, ~~2021, an increase of $7.0 million~~2022 compared to ~~$9.3~~$16.3 million of cash flows used in financing activities for the three months ended March 31, ~~2020.~~ 2021. Cash flows provided by financing activities for the three months ended March 31, 2022 consists of $227.6 million in proceeds from the initial public offering of TGR and $19.1 million of additional borrowings under our secured revolving credit facility, partially offset by $24.0 million of distributions paid to holders of common units and common units of the Operating Company (“OpCo common units”), $9.7 million used to repay borrowings under out secured revolving credit facility, $3.3 million of restricted units repurchased for tax withholding, $0.9 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units, $0.3 paid in connection with fees related to our 2021 equity offering and $0.2 million .payment of loan origination costs.

Cash flows used in financing activities for the three months ended March 31, 2021 consists of $12.3 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $3.5 million used to repay borrowings under out secured revolving credit facility, $0.9 million of restricted units repurchased for tax withholding and $0.08 million payment of loan origination costs, partially offset by $0.5 million of additional borrowings under our secured revolving credit facility. ~~Cash flows used in financing activities for the three months ended March 31, 2020 consists~~

Table of $70.0 million used to repay borrowings under our secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units and $22.7 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, partially offset by $73.6 million in proceeds from the 2020 Equity Offering and $71.1 million of additional borrowings under our secured revolving credit facility.Contents

~~Capital Expenditures~~

During the three months ended March 31, 2021, we paid approximately $0.5 million primarily in connection with the acquisition of assets from Nail Bay Royalties and Oil Nut Bay. During the three months ended March 31, 2020, we paid approximately $0.2 million primarily in connection with the acquisition of certain mineral and royalty assets from certain affiliates of Buckhorn Resources GP, LLC.

Indebtedness

On January 11, 2017, we entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the 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 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 redetermined semiannually on May 1 and 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. In connection with the November 1, 2021 redetermination under the secured revolving credit facility, the borrowing base was increased to $275.0 million. The May borrowing base redetermination is currently being conducted and is expected to be finalized by the end of May ~~2021.~~2022.

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The 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 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 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 Amended Credit Agreement also contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change of control. As of March 31, ~~2021,~~2022, we had outstanding borrowings of ~~$168.5~~$226.5 million under the secured revolving credit facility and ~~$96.5~~$48.5 million of available capacity. On April 29, 2022 we drew down $17.1 million on the senior secured revolving credit facility to fund certain operational expenses.

The 1-week and 2-month U.S. dollar LIBOR settings ceased to be published after December 31, 2021 and the U.K. Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S. dollar settings after June 30, 2023. Our secured revolving credit facility has the option of using the 1-month, 3-month or 6-month LIBOR setting and includes provisions to determine a replacement rate for LIBOR if necessary during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York. We currently do not expect the transition from LIBOR to have a material impact on us.

For additional information on our secured revolving credit facility, please read Note 8―Long-Term Debt to 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 net taxable income. We expect that substantially all of our first quarter 2022 distribution will not constitute taxable dividend income and instead will generally result in a non-taxable reduction to the tax basis of unitholders’

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common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units.

Distributions in excess of the amount taxable as dividend income will reduce a common unitholder's tax basis in its common units or produce capital gain to the 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 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 being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are encouraged to consult with your tax advisor on this matter.

New and Revised Financial Accounting Standards

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

Critical Accounting Policies and Related Estimates

~~There~~Other than those noted below related to TGR, there have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our ~~2020~~2021 Form 10-K.

Consolidation

We analyze whether we have a variable interest in an entity and whether that entity is a VIE to determine whether we are required to consolidate those entities. We perform the variable interest analysis for all entities in which we have a potential variable interest, which primarily consist of all entities in which we serve as the sponsor, general partner or managing member, and general partner entities not wholly owned by us. If we have a variable interest in the entity and the entity is a VIE, we will also analyze whether we are the primary beneficiary of this entity and whether consolidation is required.

In evaluating whether we have a variable interest in the entity, we review the equity ownership and the extent to which we absorb the risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by us are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) our other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.

For entities determined to be VIEs, we must then evaluate whether we are the primary beneficiary of such VIEs. To make this determination, we evaluate our economic interests in the entity, specifically determining if we have both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, we consider the total economics of the entity, and analyze whether our share of the economics is significant. We utilize qualitative factors, and, where applicable, quantitative factors, while performing the analysis.

VIEs for which we are the primary beneficiary have been included in our consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-

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controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represent an actively-traded money market fund of TGR, a consolidated special purpose acquisition company, which investments are invested in U.S. Treasury securities purchased with funds raised through the TGR IPO. Investments held in trust are classified as trading securities and are presented on the balance sheet at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in other income (expense)—interest income on the accompanying unaudited interim consolidated statements of operations. The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represent the shares of TGR Class A common stock sold in the TGR IPO that are redeemable for cash by the public shareholders in the event of TGR’s failure to complete the Business Combination or a tender offer. The redeemable non-controlling interests are initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. The carrying amount was accreted to its full redemption value at March 31, 2022.

Management does not believe that any other recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our financial statements.

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our ~~2020~~2021 Form 10-K. As of March 31, ~~2021,~~2022, we did not have any off-balance sheet arrangements. See Note 7—Leases to the unaudited interim ~~condensed~~ consolidated financial statements for additional information regarding our operating leases.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

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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 require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, ~~2021,~~2022, we had ~~two~~four 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 March 31, ~~2021,~~2022, we had total borrowings outstanding under our secured revolving credit facility of ~~$168.5~~$226.5 million. The impact of a 1% increase in the interest rate on this amount of debt could result in an increase in interest expense of approximately ~~$1.7~~$2.3 million annually, assuming that our indebtedness remained constant throughout the year.

On January 27, 2021, we entered into an interest rate 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 ~~89%~~66% of our outstanding balance as of March 31, ~~2021)~~2022), 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. ~~As of~~For the three months ended March 31, ~~2021,~~2022, we recognized a ~~$0.5~~$3.7 million gain on interest rate swaps which is included in other income in the accompanying unaudited interim ~~condensed~~ consolidated statements of operations.

Inflation

Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2021 through March 31, 2022. However, inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, higher commodity prices, which could result in lower revenues, supply shortages, increased costs of labor and other similar effects.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of the management of our General Partner, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ~~provide reasonable assurance~~ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the ~~U.S. Securities and Exchange Commission (the “SEC”).~~SEC. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that as of March 31, ~~2021,~~2022, our disclosure controls and procedures were effective 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

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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 have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, ~~2021~~2022 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 ~~15—~~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.

Item 1A. Risk Factors

In addition to the risks and uncertainties discussed in this Quarterly Report, ~~particularly those disclosed~~included in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks set out under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our ~~2020~~2021 Form 10-K. ~~There have been no material changes to the~~These risk factors ~~previously discussed under~~could materially affect our business, financial condition and results of operations. The unprecedented nature of the ~~heading “Risk Factors” in Item 1A. Risk Factors~~current pandemic and the volatility in the ~~Partnership’s 2020 Form 10-K.~~ ~~These~~worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks. Further, 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.

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

On March 30, 2022, we issued 9,357,919 common units to PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC (the PEP Entities”) in exchange for 9,357,919 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018 (the “Exchange Agreement”), by and among the PEP Entities, us, the General Partner, the Operating Company and the other holders of OpCo Common Units and Class B Units from time to time party thereto.

On April 22, 2022, we issued 42,081 common units to PEP II Holdings, LLC in exchange for 42,081 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement.

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

Period

Total Number of Common Units Purchased(1)

Average Price Paid per Common Unit

Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs(2)

Maximum Number of Common Units That May Yet be Purchased Under the Plans or Programs(2)
January 1, 2021 - January 31, 2021

—

$
—

—

—
February 1, 2021 - February 28, 2021

—

$
—

—

—
March 1, 2021 - March 31, 2021

85,360

$
10.78

—

—


Period	Total Number of Common Units Purchased(1)	Average Price Paid per Common Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs(2)	Maximum Number of Common Units That May Yet be Purchased Under the Plans or Programs(2)
January 1, 2022 - January 31, 2022	—	$	—	—	—
February 1, 2022 - February 28, 2022	991	$	14.47	—	—
March 1, 2022 - March 31, 2022	192,613	$	16.11	—	—

(1)

All of the common units shown above were withheld during the three months ended March 31, ~~2021~~2022 to satisfy tax-withholding obligations arising in conjunction with the vesting of restricted units. The required withholding is calculated using the closing sales price per common unit reported by the New York Stock Exchange on the date prior to the applicable vesting date.

(2)	We did not have at any time during the quarter ended March 31, ~~2021,~~2022, and currently do not have, a common unit repurchase program in place.

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Item 6. Exhibits

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

*	—filed herewith

**	—furnished herewith

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Table of Contents

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: May ~~6, 2021~~10, 2022	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: May ~~6, 2021~~10, 2022	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer

3543


Basin or Producing Region	Gross Locations(1)	Net Locations(1)	Average Gross Horizontal Wells/DSU(2)
Permian Basin	3,017	19.20	12.0
Mid‑Continent	1,489	6.38	6.8
Haynesville	1,309	17.04	5.9
Appalachia	247	2.17	7.6
Bakken	2,042	4.51	8.5
Eagle Ford	1,846	17.28	6.9
Rockies	210	1.56	10.5
Total	10,160	68.14	8.3