Kimbell Royalty Partners 10Q 2021 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2021 OR

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

For the transition period from to

Commission file number: 001-38005

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 July 30, 2021, the registrant had outstanding 42,916,472 common units representing limited partner interests and 17,611,579 Class B units representing limited partner interests.

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS


PART I – FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited):	1
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Operations	2
Condensed Consolidated Statements of Changes in Unitholders’ Equity	3
Condensed Consolidated Statements of Cash Flows	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3. Quantitative and Qualitative Disclosures About Market Risk	35
Item 4. Controls and Procedures	36


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	37
Item 1A. Risk Factors	37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 6. Exhibits	39
Signatures	40

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	12,960,623	$	9,804,977
Oil, natural gas and NGL receivables		23,718,143		17,552,756
Accounts receivable and other current assets		1,550,623		973,956
Total current assets		38,229,389		28,331,689
Property and equipment, net		2,091,907		1,964,660
Investment in affiliate (equity method)		4,917,690		5,134,951
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($193,667,499 and $225,681,626 excluded from depletion at June 30, 2021 and December 31, 2020, respectively)		1,149,610,813		1,149,095,232
Less: accumulated depreciation, depletion and impairment		(643,784,323)		(628,102,279)
Total oil and natural gas properties, net		505,826,490		520,992,953
Right-of-use assets, net		2,997,389		3,123,454
Derivative assets		725,030		—
Loan origination costs, net		4,543,940		5,086,486
Total assets	$	559,331,835	$	564,634,193

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	1,028,355	$	888,735
Other current liabilities		4,900,072		4,765,161
Derivative liabilities		22,821,751		3,113,178
Total current liabilities		28,750,178		8,767,074
Operating lease liabilities, excluding current portion		2,715,212		2,848,452
Derivative liabilities		7,901,696		3,167,685
Long-term debt		162,934,231		171,550,142
Total liabilities		202,301,317		186,333,353
Commitments and contingencies (Note 14)
Mezzanine equity:
Series A preferred units (55,000 units issued and outstanding as of June 30, 2021 and December 31, 2020)		43,897,032		42,666,102
Unitholders' equity:
Common units (42,916,472 units and 38,918,689 units issued and outstanding as of June 30, 2021 and December 31, 2020, respectively)		285,028,579		257,593,307
Class B units (17,611,579 and 20,779,781 units issued and outstanding as of June 30, 2021 and December 31, 2020, respectively)		880,579		1,038,989
Total unitholders' equity		285,909,158		258,632,296
Noncontrolling interest		27,224,328		77,002,442
Total equity		313,133,486		335,634,738
Total liabilities, mezzanine equity and unitholders' equity	$	559,331,835	$	564,634,193

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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenue
Oil, natural gas and NGL revenues	$	38,837,751	$	16,775,397	$	75,206,261	$	42,360,836
Lease bonus and other income		1,104,225		68,609		1,290,533		297,928
(Loss) gain on commodity derivative instruments, net		(14,217,186)		(4,040,972)		(28,352,914)		6,091,641
Total revenues		25,724,790		12,803,034		48,143,880		48,750,405
Costs and expenses
Production and ad valorem taxes		2,564,401		1,454,508		4,996,231		3,076,251
Depreciation and depletion expense		8,336,764		12,026,481		16,247,912		25,297,164
Impairment of oil and natural gas properties		—		65,535,973		—		136,461,704
Marketing and other deductions		2,551,222		2,049,379		5,846,508		4,180,931
General and administrative expense		6,684,830		6,865,149		13,481,215		13,389,460
Total costs and expenses		20,137,217		87,931,490		40,571,866		182,405,510
Operating income (loss)		5,587,573		(75,128,456)		7,572,014		(133,655,105)
Other income (expense)
Equity income in affiliate		273,542		4,003		458,622		167,557
Interest expense		(2,101,700)		(1,665,597)		(4,196,798)		(3,086,901)
Other (expense) income		(48,816)		—		413,955		—
Net income (loss) before income taxes		3,710,599		(76,790,050)		4,247,793		(136,574,449)
Provision for income taxes		—		—		—		—
Net income (loss)		3,710,599		(76,790,050)		4,247,793		(136,574,449)
Distribution and accretion on Series A preferred units		(1,577,968)		(1,577,968)		(3,155,936)		(4,654,652)
Net (income) loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests		(620,523)		30,362,508		(263,344)		53,947,364
Distribution on Class B units		(20,780)		(23,141)		(41,560)		(47,948)
Net income (loss) attributable to common units	$	1,491,328	$	(48,028,651)	$	786,953	$	(87,329,685)

Net income (loss) attributable to common units
Basic	$	0.04	$	(1.39)	$	0.02	$	(2.68)
Diluted	$	0.04	$	(1.39)	$	0.02	$	(2.68)
Weighted average number of common units outstanding
Basic		39,312,388		34,650,317		38,507,401		32,589,568
Diluted		41,124,489		34,650,317		40,196,053		32,589,568

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)


	Six Months Ended June 30, 2021
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Balance at January 1, 2021		38,918,689	$	257,593,307		20,779,781	$	1,038,989	$	77,002,442	$	335,634,738
Restricted units repurchased for tax withholding		(85,360)		(923,587)		—		—		—		(923,587)
Unit-based compensation		936,567		2,692,494		—		—		—		2,692,494
Distributions to unitholders		—		(7,394,551)		—		—		(3,948,160)		(11,342,711)
Distribution and accretion on Series A preferred units		—		(1,036,432)		—		—		(541,536)		(1,577,968)
Distribution on Class B units		—		(20,780)		—		—		—		(20,780)
Net income		—		352,837		—		—		184,357		537,194
Balance at March 31, 2021		39,769,896		251,263,288		20,779,781		1,038,989		72,697,103		324,999,380
Conversion of Class B units to common units		3,168,202		40,482,756		(3,168,202)		(158,410)		(40,482,756)		(158,410)
Restricted units repurchased for tax withholding		(21,626)		(220,677)		—		—		—		(220,677)
Unit-based compensation		—		2,743,917		—		—		—		2,743,917
Distributions to unitholders		—		(10,732,033)		—		—		(5,610,542)		(16,342,575)
Distribution and accretion on Series A preferred units		—		(1,118,834)		—		—		(459,134)		(1,577,968)
Distribution on Class B units		—		(20,780)		—		—		—		(20,780)
Net income		—		2,630,942		—		—		1,079,657		3,710,599
Balance at June 30, 2021		42,916,472	$	285,028,579		17,611,579	$	880,579	$	27,224,328	$	313,133,486

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

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

(Unaudited)


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

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)


	Six Months Ended June 30,
	2021		2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	4,247,793	$	(136,574,449)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and depletion expense		16,247,912		25,297,164
Impairment of oil and natural gas properties		—		136,461,704
Amortization of right-of-use assets		145,701		135,959
Amortization of loan origination costs		753,484		532,636
Equity income in affiliate		(458,622)		(167,557)
Cash distribution from affiliate		490,280		—
Forfeiture of restricted units		—		(106,245)
Unit-based compensation		5,436,411		4,641,785
Loss (gain) on derivative instruments, net of settlements		23,717,554		(2,076,722)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(6,165,387)		7,404,091
Accounts receivable and other current assets		(576,667)		(310,909)
Accounts payable		139,620		(17,521)
Other current liabilities		134,911		460,751
Operating lease liabilities		(152,876)		(135,661)
Net cash provided by operating activities		43,960,114		35,545,026
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(693,114)		(45,096)
Purchase of oil and natural gas properties		(515,582)		(87,418,135)
Investment in affiliate		—		(1,274,900)
Cash distribution from affiliate		185,603		246,411
Net cash used in investing activities		(1,023,093)		(88,491,720)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity offering		—		73,601,668
Redemption of Class B contributions on converted units		(158,410)		(245,678)
Redemption on Series A preferred units		—		(61,089,600)
Distributions to common unitholders		(18,126,584)		(17,357,045)
Distribution to OpCo unitholders		(9,558,702)		(13,550,966)
Distribution and accretion on Series A preferred units		(1,925,006)		(2,887,503)
Distribution on Class B units		(41,560)		(47,948)
Borrowings on long-term debt		4,484,089		156,588,126
Repayments on long-term debt		(13,100,000)		(85,000,000)
Payment of loan origination costs		(210,938)		—
Restricted units repurchased for tax withholding		(1,144,264)		(6,259)
Net cash (used in) provided by financing activities		(39,781,375)		50,004,795
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		3,155,646		(2,941,899)
CASH AND CASH EQUIVALENTS, beginning of period		9,804,977		14,204,250
CASH AND CASH EQUIVALENTS, end of period	$	12,960,623	$	11,262,351
Supplemental cash flow information:
Cash paid for interest	$	3,434,483	$	2,544,173
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties	$	—	$	28,140,093
Non-cash deemed distribution to Series A preferred units	$	1,230,930	$	1,767,149
Noncash effect of Series A preferred unit redemption	$	—	$	25,847,891

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

Table of Contents

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

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission. As a result, the accompanying unaudited interim condensed consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim condensed consolidated financial statements and related notes should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020 (the “2020 Form 10-K”), which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the 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. 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.

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

Segment Reporting

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

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

The global spread of coronavirus (“COVID-19”) created significant volatility, uncertainty, and economic disruption 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.

Table of Contents

The pandemic reached more than 200 countries and 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 during the 2020 period. The significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of 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. In the first half of 2021, both pricing and activity began to improve, with oil prices rising above pre-COVID-19 levels. In spite of further stabilization in the oil and natural gas markets and improved differentials and commodity prices, the Partnership believes that the ongoing COVID-19 outbreak and potential supply and demand imbalances in the oil and natural gas markets could have an adverse effect on the Partnership’s business, production, cash flows, financial condition and results of operations during 2021.

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 to the extent possible. Beginning in mid-May 2020, the Partnership opened its offices to employees on a voluntary basis, with employees having the option to work from the office or from home. The Partnership will continue to give employees the option to work from the office or from home until the CDC recommends businesses and employers resume to pre-pandemic operations. These restrictions have had minimal impact on the Partnership’s operations to date and have allowed the Partnership to maintain the engagement and connectivity of its personnel, as well as minimize the number of employees in the office.

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 remain dependent on a number of factors, including, among others, the ultimate severity of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other thirds parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s 2020 Form 10-K, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the three and six months ended June 30, 2021, other than those discussed below in Recently Adopted Accounting Pronouncements.

Recently Adopted Accounting Pronouncements

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 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the three and six months ended June 30, 2021.

Table of Contents

NOTE 3—ACQUISITIONS AND JOINT VENTURES

Acquisitions

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

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

Joint Ventures

On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed $10.0 million. The Joint Venture is managed by Springbok Operating Company, LLC. While certain members of Springbok Operating Company, LLC are affiliated with the entities acquired as part of the Springbok Acquisition, none of the assets held by the Joint Venture were included in the Springbok Acquisition. The purpose of the Joint Venture is to make direct or indirect investments in royalty, mineral and overriding royalty interests and similar non-cost bearing interests in oil and gas properties, excluding leasehold or working interests. The Partnership utilizes the equity method of accounting for its investment in the Joint Venture. As of June 30, 2021, the Partnership had paid approximately $5.2 million under its capital commitment.

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 June 30, 2021, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The Partnership hedges its production based on the amount of debt and/or preferred equity as a percent of its enterprise value. As of June 30, 2021, these economic hedges constituted approximately 33% of daily oil and natural gas production.

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

Table of Contents

(which represented approximately 92% of our outstanding balance as of June 30, 2021), at approximately 3.9% for the period ending on January 29, 2024. The Partnership uses an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps are recognized as gains or losses in the current period and are presented on a net basis within other income in the accompanying unaudited interim condensed consolidated statements of operations. As of June 30, 2021, the interest rate swap had a total notional amount of $150.0 million and a fair value of $0.5 million.

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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Beginning fair value of derivative instruments	$	(18,955,035)	$	9,783,362	$	(6,280,863)	$	804,501
(Loss) gain on derivative instruments		(14,266,002)		(4,040,972)		(27,938,959)		6,091,641
Net cash paid (received) on settlements of derivative instruments		3,222,620		(2,861,167)		4,221,405		(4,014,919)
Ending fair value of derivative instruments	$	(29,998,417)	$	2,881,223	$	(29,998,417)	$	2,881,223

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


		June 30,		December 31,
Classification	Balance Sheet Location	2021		2020
Assets:
Long-term assets	Derivative assets	$	725,030	$	—
Liabilities:
Current liabilities	Derivative liabilities		(22,821,751)		(3,113,178)
Long-term liabilities	Derivative liabilities		(7,901,696)		(3,167,685)
		$	(29,998,417)	$	(6,280,863)

As of June 30, 2021, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps


	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High
June 2021 - December 2021	313,938	$	44.09	$	35.63	$	54.52
January 2022 - December 2022	500,552	$	41.86	$	35.65	$	46.00
January 2023 - June 2023	162,743	$	56.77	$	53.38	$	61.16

Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
July 2021 - December 2021	3,471,344	$	2.45	$	2.33	$	2.58
January 2022 - December 2022	6,357,449	$	2.46	$	2.23	$	2.70
January 2023 - June 2023	2,202,487	$	2.63	$	2.52	$	2.73

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 June 30, 2021 and December 31, 2020 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.

Table of Contents

●

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

●

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and six months ended June 30, 2021 and 2020.

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

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


	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total
June 30, 2021
Assets
Interest rate swap contracts	$	—	$	725,030	$	—	$	—	$	725,030
Liabilities
Commodity derivative contracts	$	—	$	(30,500,865)	$	—	$	—	$	(30,500,865)
Interest rate swap contracts	$	—	$	(222,582)	$	—	$	—	$	(222,582)
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:


	June 30,		December 31,
	2021		2020
Oil and natural gas properties
Proved properties	$	955,943,314	$	923,413,606
Unevaluated properties		193,667,499		225,681,626
Less: accumulated depreciation, depletion and impairment		(643,784,323)		(628,102,279)
Total oil and natural gas properties	$	505,826,490	$	520,992,953

The Partnership assesses all unevaluated properties on a periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions, operators’ intent to drill, remaining lease term, geological and geophysical evaluations, operators’ drilling results and activity, the assignment of proved 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

Table of Contents

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 first quarter of 2020 equal to the amount of the transfer.

After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated proved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties in the first quarter of 2020. The Partnership did not book PUD reserves in its total estimated proved reserves as of June 30, 2021 or December 31, 2020 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 the three and six months ended June 30, 2021. The Partnership recorded an impairment on its oil and natural gas properties of $65.5 million and $136.5 million for the three and six months ended June 30, 2020, respectively, which can primarily be attributed to factors mentioned above.

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 June 30, 2021 is 7.84 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 six months ended June 30, 2021.

Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying unaudited interim condensed consolidated statements of operations for the three and six months ended June 30, 2021 and 2020. The total operating lease expense recorded for both the three months ended June 30, 2021 and 2020 was $0.1 million. The total operating lease expense recorded for both the six months ended June 30, 2021 and 2020 was $0.2 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 June 30, 2021 were as follows:


	Total		2021		2022		2023		2024		2025		Thereafter
Operating leases	$	3,929,323	$	242,818	$	486,045	$	487,787	$	488,725	$	497,033	$	1,726,915
Less: Imputed Interest		(922,484)
Total	$	3,006,839

Table of Contents

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 (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 the change in administrative agent from Frost to with Citibank, N.A., New York (“Citibank”) under the Amended Credit Agreement, (iv) increase the applicable margin under the 2018 Amended Credit Agreement, which varies based upon the level of borrowing base usage, by 1.00% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 2.00% to 3.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 3.00% to 4.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement), (v) provide for a LIBOR (as defined in the Amended Credit Agreement) floor of 0.25%, (vi) modify the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) financial covenant to permit the numerator of the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) to be calculated as Total Debt (as defined in the Amended Credit Agreement) minus up to $25 million in unrestricted cash held by the Partnership and its restricted subsidiaries and to decreases the maximum permitted Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) from 4.0 to 1.0 to 3.5 to 1.0, and (vii) modify the conditions permitting restricted distributions to holders of Kimbell Common Units (as defined in the Amended Credit Agreement) including, among other things, a limitation on such distributions to not be in excess of the Partnership’s Projected Cash Available For Distribution (as defined in the Amended Credit Agreement). In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be 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 May 1, 2021 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $265.0 million.

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 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 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 six months ended June 30, 2021, the Partnership borrowed an additional $4.5 million under the secured revolving credit facility and repaid approximately $13.1 million of the outstanding borrowings. As of June 30, 2021, the Partnership’s outstanding balance was $162.9 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of June 30, 2021.

Table of Contents

As of June 30, 2021, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 3.50% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.50%. For both the three and six months ended June 30, 2021, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.75%.

NOTE 9—PREFERRED UNITS

In July 2018, the Partnership completed the private placement of 110,000 Series A preferred units to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $110.0 million. Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the third anniversary of the original issuance date, and board appointment rights beginning on the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units.

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 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 six months ended June 30, 2020.

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


		Series A
		Preferred Units
Balance at December 31, 2020		55,000
Balance at June 30, 2021		55,000

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

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

In January 2020, the Partnership completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 million (the “2020 Equity Offering”). The Partnership used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. In

Table of Contents

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.

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


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

(1)	Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on February 25, 2021.

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


	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2021	$	0.27	April 23, 2021	May 3, 2021	May 10, 2021
Q2 2021	$	0.31	July 23, 2021	August 2, 2021	August 9, 2021

Q1 2020	$	0.17	April 24, 2020	May 4, 2020	May 11, 2020
Q2 2020	$	0.13	July 24, 2020	August 3, 2020	August 10, 2020

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


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

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

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

NOTE 11—EARNINGS (LOSS) PER COMMON UNIT

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

Table of Contents

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net income (loss) attributable to common units	$	1,491,328	$	(48,028,651)	$	786,953	$	(87,329,685)

Weighted average number of common units outstanding:
Basic		39,312,388		34,650,317		38,507,401		32,589,568
Effect of dilutive securities:
Series A preferred units		—		—		—		—
Class B units		—		—		—		—
Restricted units		1,812,101		—		1,688,652		—
Diluted		41,124,489		34,650,317		40,196,053		32,589,568

Net income (loss) attributable to common units
Basic	$	0.04	$	(1.39)	$	0.02	$	(2.68)
Diluted	$	0.04	$	(1.39)	$	0.02	$	(2.68)

The calculation of diluted net loss per unit for the three and six months ended June 30, 2020 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 1,512,938 of unvested restricted units 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.

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


		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2020	1,276,546	$	13.604	1.788 years
Awarded	936,567		10.350	—
Vested	(419,535)		13.460	—
Unvested at June 30, 2021	1,793,578	$	11.938	2.041 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 Partnership’s Sponsors may identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate

Table of Contents

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.

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

During the three and six months ended June 30, 2021, 0 monthly services fee was paid to BJF Royalties. During the three months ended June 30, 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. During the six months ended June 30, 2021, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $60,000, $150,657 and $274,240, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s LTIP.

NOTE 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 June 30, 2021.

NOTE 15—SUBSEQUENT EVENTS

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

Redemption of Preferred Units

On July 7, 2021, the Partnership completed the redemption of 30,000 Series A preferred units, representing 55% of the then-outstanding Series A preferred units, with 25,000 Series A preferred units still outstanding. The Series A preferred units were redeemed at a price of $1,202.51 per Series A preferred unit for an aggregate redemption price of $36.1 million.

Debt

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

Special Purpose Acquisition Company

On July 29, 2021, Kimbell Tiger Acquisition Corporation (“TGR”), the Partnership’s newly formed special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the Securities and Exchange Commission. TGR’s proposed public offering is expected to have a base offering size of $200.0 million, or up to $230.0 million if the underwriter’s over-allotment is exercised in full. The Partnership, through an indirect subsidiary, would own approximately 20% of TGR’s issued and outstanding common stock upon the consummation of the proposed offering. Certain members of the Partnership’s management and members of the Board of Directors are members of the sponsor of TGR. As of June 30, 2021, we incurred $0.2 million in deferred offering costs related to the proposed offering, which is included in other current assets in our unaudited interim condensed consolidated balance sheets.

Distributions

On August 3, 2021, the Partnership paid a quarterly cash distribution on the Series A preferred units of approximately $0.4 million for the quarter ended June 30, 2021.

On August 3, 2021, the Partnership paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of $17,612 for the quarter ended June 30, 2021.

Table of Contents

On July 23, 2021, the Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended June 30, 2021. The distribution will be paid on August 9, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on August 2, 2021.

Table of Contents

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 (the “2020 Form 10-K”).

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

Cautionary Statement Regarding Forward-Looking Statements

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

●

our ability to replace our reserves;

●

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

●

our ability to execute our business strategies;

●

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

●

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

Table of Contents

●

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;

●

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

●

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

These factors are discussed in further detail in the 2020 Form 10-K under “Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II and elsewhere in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

Overview

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

Table of Contents

As of June 30, 2021, we owned mineral and royalty interests in approximately 9.1 million gross acres and overriding royalty interests in approximately 4.6 million gross acres, with approximately 60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of June 30, 2021, over 98% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 97,000 gross wells, including over 41,000 wells in the Permian Basin.

The following table summarizes our ownership in United States basins and producing regions and information about the wells in which we have a mineral or royalty interest as of June 30, 2021:


			Average Daily	Average Daily
			Production	Production
Basin or Producing Region	Gross Acreage	Net Acreage	(Boe/d)(6:1)(1)	(Boe/d)(20:1)(2)	Well Count
Permian Basin	2,662,777	23,075	2,398	1,875	41,075
Mid‑Continent	3,955,148	41,402	1,671	1,018	11,267
Haynesville	786,724	7,665	3,466	1,185	8,861
Appalachia	741,354	23,202	2,103	882	3,208
Bakken	1,569,637	6,051	716	599	4,124
Eagle Ford	624,148	6,730	1,465	1,150	3,235
Rockies	74,152	1,036	1,278	820	12,359
Other	3,232,561	36,694	1,296	747	13,028
Total	13,646,501	145,855	14,393	8,276	97,157

(1)

“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read “Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves” in our 2020 Form 10-K.

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

The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of June 30, 2021:


Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	302	292	0.64	0.77
Mid‑Continent	120	61	0.30	0.06
Haynesville	73	39	0.27	0.15
Appalachia	22	39	0.09	0.13
Bakken	162	156	0.27	0.68
Eagle Ford	71	73	0.33	0.59
Rockies	49	43	0.05	0.29
Total	799	703	1.95	2.67

(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

Redemption of Preferred Units

On July 7, 2021, we completed the redemption of 30,000 Series A preferred units, representing 55% of the then-outstanding Series A preferred units, with 25,000 Series A preferred units still outstanding. The Series A preferred units were redeemed at a price of $1,202.51 per Series A preferred unit for an aggregate redemption price of $36.1 million.

Table of Contents

Debt

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

Special Purpose Acquisition Company

On July 29, 2021, TGR, our newly formed special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the Securities and Exchange Commission. TGR’s proposed public offering is expected to have a base offering size of $200.0 million, or up to $230.0 million if the underwriter’s over-allotment is exercised in full. We, through an indirect subsidiary, would own approximately 20% of TGR’s issued and outstanding common stock upon the consummation of the proposed offering. Certain members of our management and members of the General Partner’s Board of Directors (the “Board of Directors”) are members of the sponsor of TGR. As of June 30, 2021, we incurred $0.2 million in deferred offering costs related to the proposed offering, which is included in other current assets in our unaudited interim condensed consolidated balance sheets.

Quarterly Distributions

On August 3, 2021, we paid a quarterly cash distribution on the Series A preferred units of approximately $0.4 million for the quarter ended June 30, 2021.

Each holder of Class B units has paid five cents per Class B unit to us as an additional capital contribution for the Class B units (such aggregate amount, the “Class B Contribution”) in exchange for Class B units. Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution. On August 3, 2021, we paid a quarterly cash distribution to each Class B unitholder, resulting in a total quarterly distribution of $17,612 for the quarter ended June 30, 2021.

On July 23, 2021, Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended June 30, 2021. The distribution will be paid on August 9, 2021 to common unitholders and OpCo common unitholders of record as of the close of business on August 2, 2021.

Business Environment

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

The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption during 2020 and continuing into early 2021. On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic reached more than 200 countries and resulted in widespread adverse impacts on the global economy, our oil, natural gas, and NGL operators and other parties with whom we have business relations, including a significant reduction in the global demand for oil and natural gas during the 2020 period. The significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance led to a significantly weaker outlook for oil and gas producers and had a disruptive impact on the oil and natural gas industry. Globally, these conditions led to significant economic contraction during the 2020 period. In the first half of 2021, both pricing and activity began to improve, with oil prices rising above pre-COVID-19 levels. In spite of further stabilization in the oil and natural gas markets and improved differentials and commodity prices, the we believe that the ongoing COVID-19 outbreak and potential supply and demand imbalances in the oil and natural gas markets could have an adverse effect on our business, production, cash flows, financial condition and results of operations during 2021.

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

Table of Contents

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 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. While shelter-in-place restrictions subsided in the second half of 2020 and through 2021, the possibility of future restrictions remains. One of the largest impacts of the pandemic has been a significant reduction in global demand for oil and, to a lesser extent, natural gas. This significant decline in demand was met with a sharp decline in oil prices which were exacerbated by the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries. The resulting supply and demand imbalance had disruptive impacts on the oil and natural gas exploration and production industry and on other related industries in 2020. These industry conditions, coupled with those resulting from the COVID-19 pandemic, led to significant global economic contraction generally and in our industry in particular.

Oil and natural gas prices have historically been volatile; however, the volatility in the prices for these commodities substantially increased for the 2020 period as a result of COVID-19, the OPEC announcements mentioned above and ongoing storage capacity concerns. Oil prices declined sharply in April 2020. Although strip pricing for natural gas has increased meaningfully, the impact of these developments on our business and the oil and gas industry is unpredictable. We derived approximately 36% of our revenues and 61% of our production on a Boe/d basis (6:1) from natural gas for the six months ended June 30, 2021, which we believe presents some downside protection against depressed oil prices.

The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on our business, cash flows, liquidity, financial condition and results of operations remain dependent on a number of factors, including, among others, the ultimate severity of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other third parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in Part I, Item 1A. Risk Factors in our 2020 Form 10-K.

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, 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”).


	Six Months Ended June 30, 2021				Six Months Ended June 30, 2020
	High		Low		High		Low
Oil ($/Bbl)	$	74.21	$	47.47	$	63.27	$	(36.98)
Natural gas ($/MMBtu)	$	23.86	$	2.43	$	2.17	$	1.42

On July 30, 2021, the West Texas Intermediate posted price for crude oil was $73.93 per Bbl and the Henry Hub spot market price of natural gas was $3.94 per MMBtu.

Table of Contents

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Oil ($/Bbl)	$	66.19	$	27.96	$	62.21	$	36.58
Natural gas ($/MMBtu)	$	2.95	$	1.70	$	3.22	$	1.80

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 increased by 82.9% to 459 active land rigs at June 30, 2021 compared to 251 active land rigs at June 30, 2020. The 459 active land rigs at June 30, 2021 increased by 10.3% from 416 active land rigs at March 31, 2021. The increase in rig count is primarily attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas prices.

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


	June 30,
Basin or Producing Region	2021	2020
Permian Basin	23	11
Mid‑Continent	6	2
Haynesville	11	5
Appalachia	1	3
Bakken	6	5
Eagle Ford	3	1
Rockies	—	2
Total	50	29

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 revenue for the following periods:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Royalty income
Oil sales	54	%	55	%	51	%	57	%
Natural gas sales	32	%	37	%	36	%	34	%
NGL sales	11	%	7	%	11	%	8	%
Lease bonus and other income	3	%	1	%	2	%	1	%
	100	%	100	%	100	%	100	%

We have entered into oil and natural gas commodity derivative agreements, which extend through June 2023, to establish, in advance, a price for the sale of a portion of the oil, natural gas and NGLs produced from our mineral and royalty interests.

Table of Contents

Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution

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

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

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

Table of Contents

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Reconciliation of net income (loss) to Adjusted EBITDA and cash available for distribution:
Net income (loss)	$	3,710,599	$	(76,790,050)	$	4,247,793	$	(136,574,449)
Depreciation and depletion expense		8,336,764		12,026,481		16,247,912		25,297,164
Interest expense		2,101,700		1,665,597		4,196,798		3,086,901
Cash distribution from affiliate		273,542		—		490,280		—
Provision for income taxes		—		—		—		—
EBITDA		14,422,605		(63,097,972)		25,182,783		(108,190,384)
Impairment of oil and natural gas properties		—		65,535,973		—		136,461,704
Unit-based compensation		2,743,917		2,534,198		5,436,411		4,641,785
Loss (gain) on derivative instruments, net of settlements		11,043,382		6,902,139		23,717,554		(2,076,722)
Cash distribution from affiliate		130,564		228,450		185,603		246,411
Equity income in affiliate		(273,542)		(4,003)		(458,622)		(167,557)
Consolidated Adjusted EBITDA		28,066,926		12,098,785		54,063,729		30,915,237
Adjusted EBITDA attributable to noncontrolling interest		(8,166,509)		(4,687,492)		(17,088,239)		(11,747,239)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		19,900,417		7,411,293		36,975,490		19,167,998
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		1,248,697		868,315		2,347,784		1,572,267
Cash distributions on Series A preferred units		682,446		589,594		1,314,630		1,792,353
Restricted units repurchased for tax withholding		156,468		—		763,093		—
Distributions on Class B units		20,780		23,141		41,560		47,948
Cash available for distribution on common units	$	17,792,026	$	5,930,243	$	32,508,423	$	15,755,430

Table of Contents


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution:
Net cash provided by operating activities	$	28,479,121	$	14,757,420	$	43,960,114	$	35,545,026
Interest expense		2,101,700		1,665,597		4,196,798		3,086,901
Provision for income taxes		—		—		—		—
Impairment of oil and natural gas properties		—		(65,535,973)		—		(136,461,704)
Amortization of right-of-use assets		(73,916)		(68,489)		(145,701)		(135,959)
Amortization of loan origination costs		(381,997)		(266,318)		(753,484)		(532,636)
Equity income in affiliate		273,542		4,003		458,622		167,557
Forfeiture of restricted units		—		106,245		—		106,245
Unit-based compensation		(2,743,917)		(2,534,198)		(5,436,411)		(4,641,785)
(Loss) gain on derivative instruments, net of settlements		(11,043,382)		(6,902,139)		(23,717,554)		2,076,722
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(1,049,948)		(2,491,042)		6,165,387		(7,404,091)
Accounts receivable and other current assets		(7,195)		(198,076)		576,667		310,909
Accounts payable		14,061		(433,058)		(139,620)		17,521
Other current liabilities		(1,227,198)		(1,270,345)		(134,911)		(460,751)
Operating lease liabilities		81,734		68,401		152,876		135,661
EBITDA		14,422,605		(63,097,972)		25,182,783		(108,190,384)
Add:
Impairment of oil and natural gas properties		—		65,535,973		—		136,461,704
Unit-based compensation		2,743,917		2,534,198		5,436,411		4,641,785
Loss (gain) on derivative instruments, net of settlements		11,043,382		6,902,139		23,717,554		(2,076,722)
Cash distribution from affiliate		130,564		228,450		185,603		246,411
Equity income in affiliate		(273,542)		(4,003)		(458,622)		(167,557)
Consolidated Adjusted EBITDA		28,066,926		12,098,785		54,063,729		30,915,237
Adjusted EBITDA attributable to noncontrolling interest		(8,166,509)		(4,687,492)		(17,088,239)		(11,747,239)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		19,900,417		7,411,293		36,975,490		19,167,998
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		1,248,697		868,315		2,347,784		1,572,267
Cash distributions on Series A preferred units		682,446		589,594		1,314,630		1,792,353
Restricted units repurchased for tax withholding		156,468		—		763,093		—
Distributions on Class B units		20,780		23,141		41,560		47,948
Cash available for distribution on common units	$	17,792,026	$	5,930,243	$	32,508,423	$	15,755,430

Factors Affecting the Comparability of Our Results to Our Historical Results

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

Ongoing Acquisition Activities

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

Table of Contents

party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three and six months ended June 30, 2021 and 2020 include the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”).

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

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

Impairment of Oil and Natural Gas Properties

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

We did not record an impairment on our oil and natural gas properties for the three and six months ended June 30, 2021. For the three and six months ended June 30, 2020, we recorded an impairment on our oil and natural gas properties of $65.5 million and $136.5 million, respectively, 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 in the first quarter of 2020. We similarly recorded an impairment on the value of our unevaluated oil and natural gas properties in the first quarter of 2020, which primarily were acquired in various acquisitions since our initial public offering. There were no additional impairments to unevaluated properties in the second quarter of 2020.

Table of Contents

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.

Results of Operations

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	38,837,751	$	16,775,397	$	75,206,261	$	42,360,836
Lease bonus and other income		1,104,225		68,609		1,290,533		297,928
(Loss) gain on commodity derivative instruments, net		(14,217,186)		(4,040,972)		(28,352,914)		6,091,641
Total revenues		25,724,790		12,803,034		48,143,880		48,750,405
Costs and expenses
Production and ad valorem taxes		2,564,401		1,454,508		4,996,231		3,076,251
Depreciation and depletion expense		8,336,764		12,026,481		16,247,912		25,297,164
Impairment of oil and natural gas properties		—		65,535,973		—		136,461,704
Marketing and other deductions		2,551,222		2,049,379		5,846,508		4,180,931
General and administrative expenses		6,684,830		6,865,149		13,481,215		13,389,460
Total costs and expenses		20,137,217		87,931,490		40,571,866		182,405,510
Operating income (loss)		5,587,573		(75,128,456)		7,572,014		(133,655,105)
Other income (expense)
Equity income in affiliate		273,542		4,003		458,622		167,557
Interest expense		(2,101,700)		(1,665,597)		(4,196,798)		(3,086,901)
Other (expense) income		(48,816)		—		413,955		—
Net income (loss) before income taxes		3,710,599		(76,790,050)		4,247,793		(136,574,449)
Provision for income taxes		—		—		—		—
Net income (loss)		3,710,599		(76,790,050)		4,247,793		(136,574,449)
Distribution and accretion on Series A preferred units		(1,577,968)		(1,577,968)		(3,155,936)		(4,654,652)
Net (income) loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests		(620,523)		30,362,508		(263,344)		53,947,364
Distribution on Class B units		(20,780)		(23,141)		(41,560)		(47,948)
Net income (loss) attributable to common units	$	1,491,328	$	(48,028,651)	$	786,953	$	(87,329,685)
Production Data:
Oil (Bbls)		338,873		364,445		658,522		698,594
Natural gas (Mcf)		4,770,839		4,417,134		9,271,153		8,681,479
Natural gas liquids (Bbls)		175,706		159,985		340,895		330,674
Combined volumes (Boe) (6:1)		1,309,719		1,260,619		2,544,609		2,476,181

Comparison of the Three Months Ended June 30, 2021 to the Three Months Ended June 30, 2020

Oil, Natural Gas and NGL Revenues

For the three months ended June 30, 2021, our oil, natural gas and NGL revenues were $38.8 million, an increase of $22.0 million from $16.8 million for the three months ended June 30, 2020. 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 June 30, 2021 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 1,309,719 Boe or 14,393 Boe/d, for the three months ended June 30, 2021, an increase of 49,100 Boe or 139 Boe/d, from 1,260,619 Boe or 14,254 Boe/d, for the three months ended June 30,

Table of Contents

2020. The increase in production for the three months ended June 30, 2021 was primarily attributable to production associated with the Springbok Acquisition, which accounted for 42,506 Boe or 66 Boe/d.

Our operators received an average of $63.47 per Bbl of oil, $2.69 per Mcf of natural gas and $25.71 per Bbl of NGL for the volumes sold during the three months ended June 30, 2021 compared to $25.40 per Bbl of oil, $1.43 per Mcf of natural gas and $7.54 per Bbl of NGL for the volumes sold during the three months ended June 30, 2020. These average prices received during the three months ended June 30, 2021 increased 149.9% or $38.07 per Bbl of oil and 88.1% or $1.26 per Mcf of natural gas as compared to the three months ended June 30, 2020. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 136.7% or $38.23 per Bbl of oil and 73.5% or $1.25 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income increased by $1.0 million to $1.1 million for the three months ended June 30, 2021 compared to $0.07 million for the three months ended June 30, 2020. The increase in lease bonus and other income is ultimately a result of the volatility and uncertainty experienced in the oil and gas market for the 2020 period, which discouraged operators from drilling new wells.

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended June 30, 2021 included $11.1 million of mark-to-market losses and $3.2 million of losses on the settlement of commodity derivative instruments compared to $6.9 million of mark-to-market losses and $2.9 million of gains on the settlement of commodity derivative instruments for the three months ended June 30, 2020. We recorded a mark-to-market loss for the three months ended June 30, 2021 as a result of the increase in strip pricing from the three months ended March 31, 2021 to the three months ended June 30, 2021. We recorded a mark-to-market loss for the three months ended June 30, 2020 as a result of the increase in strip pricing from the three months ended March 31, 2020 to the three months ended June 30, 2020.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended June 30, 2021 were $2.6 million, an increase of $1.1 million from $1.5 million for the three months ended June 30, 2020. The increase in production and ad valorem taxes was primarily related to the significant increase in the average prices we received for oil, natural gas and NGL production for the three months ended June 30, 2021.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended June 30, 2021 was $8.3 million, a decrease of $3.7 million from $12.0 million for the three months ended June 30, 2020. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2020, which significantly reduced our net capitalized oil and natural gas properties.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $6.11 for the three months ended June 30, 2021, a decrease of $3.37 per barrel from the $9.48 average depletion rate per barrel for the three months ended June 30, 2020. The decrease in the depletion rate was due to the significant impairment that was recorded during the year ended December 31, 2020, which significantly reduced 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 June 30, 2021. We recorded an impairment expense on our oil and natural gas properties of $65.5 million during the three months ended June 30, 2020. The impairment recorded during the three months ended June 30, 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

Table of Contents

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 June 30, 2021 were $2.6 million, an increase of $0.6 million from $2.0 million for the three months ended June 30, 2020.

General and Administrative Expenses

General and administrative expenses remained relatively flat at $6.7 million and $6.9 million for the three months ended June 30, 2021 and 2020, respectively.

Interest Expense

Interest expense for the three months ended June 30, 2021 was $2.1 million compared to $1.7 million for the three months ended June 30, 2020. The increase in interest expense was primarily due to debt incurred in 2020 to fund the Springbok Acquisition.

Comparison of the Six Months Ended June 30, 2021 to the Six Months Ended June 30, 2020

Oil, Natural Gas and NGL Revenues

For the six months ended June 30, 2021, our oil, natural gas and NGL revenues were $75.2 million, an increase of $32.8 million from $42.4 million for the six months ended June 30, 2020. 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 six months ended June 30, 2021 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 2,544,609 Boe or 14,059 Boe/d, for the six months ended June 30, 2021, an increase of 68,428 Boe or 454 Boe/d, from 2,476,181 Boe or 13,605 Boe/d, for the six months ended June 30, 2020. The increase in production for the six months ended June 30, 2021 was primarily attributable to production associated with the Springbok Acquisition, which accounted for 222,572 Boe. The increase was offset by a reduction in production on our other assets as a result 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.

Our operators received an average of $59.13 per Bbl of oil, $2.99 per Mcf of natural gas and $25.10 per Bbl of NGL for the volumes sold during the six months ended June 30, 2021 compared to $34.90 per Bbl of oil, $1.67 per Mcf of natural gas and $10.54 per Bbl of NGL for the volumes sold during the six months ended June 30, 2020. These average prices received during the six months ended June 30, 2021 increased 69.4% or $24.23 per Bbl of oil and 79.0% or $1.32 per Mcf of natural gas as compared to the six months ended June 30, 2020. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 70.1% or $25.63 per Bbl of oil and 78.9% or $1.42 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income increased by $1.0 million to $1.3 million for the six months ended June 30, 2021 compared to $0.3 million for the six months ended June 30, 2020. The increase in lease bonus and other income is ultimately a result of the volatility and uncertainty experienced in the oil and gas market for the 2020 period, which discouraged operators from drilling new wells.

Table of Contents

(Loss) Gain on Commodity Derivative Instruments

Loss on commodity derivative instruments for the six months ended June 30, 2021 included $24.2 million of mark-to-market losses and $4.1 million of losses on the settlement of commodity derivative instruments compared to $2.1 million of mark-to-market gains and $4.0 million of gains on the settlement of commodity derivative instruments for the six months ended June 30, 2020. We recorded a mark-to-market loss for the six months ended June 30, 2021 as a result of the increase in strip pricing from the three months ended December 31, 2020 to the three months ended March 31, 2021 and an increase in strip pricing from the three months ended March 31, 2021 to the three months ended June 30, 2021. The mark-to-market gain for the six months ended June 30, 2020 was attributable to the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts, which was partially offset by the increase in volumes hedged due to the Springbok Acquisition.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the six months ended June 30, 2021 were $5.0 million, an increase of $1.9 million from $3.1 million for the six months ended June 30, 2020. The increase in production and ad valorem taxes was primarily attributable to the increase in the average prices we received for oil, natural gas and NGL production for the six months ended June 30, 2021, and to a lesser extent, production and ad valorem taxes associated with the Springbok Acquisition.

Depreciation and Depletion Expense

Depreciation and depletion expense for the six months ended June 30, 2021 was $16.2 million, a decrease of $9.1 million from $25.3 million for the six months ended June 30, 2020. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2020, which significantly reduced our net capitalized oil and natural gas properties.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $6.16 for the six months ended June 30, 2021, a decrease of $4.00 per barrel from the $10.16 average depletion rate per barrel for the six months ended June 30, 2020. The decrease in the depletion rate was due to the significant impairment that was recorded during the year ended December 31, 2020, which significantly reduced 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 six months ended June 30, 2021. We recorded an impairment expense on our oil and natural gas properties of $136.5 million during the six months ended June 30, 2020. The impairment recorded during the six months ended June 30, 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 six months ended June 30, 2021 were $5.8 million, an increase of $1.6 million from $4.2 million for the six months ended June 30, 2020, which was primarily attributable to the Springbok Acquisition.

General and Administrative Expenses

General and administrative expenses remained relatively flat at $13.5 million for the six months ended June 30, 2021 compared to $13.4 million for the six months ended June 30, 2020.

Interest Expense

Table of Contents

Interest expense for the six months ended June 30, 2021 was $4.2 million compared to $3.1 million for the six months ended June 30, 2020. The increase in interest expense was primarily due to debt incurred in 2020 to fund the Springbok Acquisition.

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 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 second quarter of 2021 for the repayment of $6.3 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the second quarter of 2021. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and 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 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 distributions.

Table of Contents

Cash Flows

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


	Six Months Ended June 30,
	2021		2020
Cash Flow Data:
Net cash provided by operating activities	$	43,960,114	$	35,545,026
Net cash used in investing activities		(1,023,093)		(88,491,720)
Net cash (used in) provided by financing activities		(39,781,375)		50,004,795
Net increase (decrease) in cash and cash equivalents	$	3,155,646	$	(2,941,899)

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 six months ended June 30, 2021 were $44.0 million, an increase of $8.5 million compared to $35.5 million for the six months ended June 30, 2020. 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 six months ended June 30, 2021.

Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2021 decreased by $87.5 million compared to the six months ended June 30, 2020. For the six months ended June 30, 2021, we used $0.7 million primarily to fund the renovation of office space and $0.5 million primarily to fund the acquisition of assets from Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP (“Oil Nut Bay”), partially offset by a $0.2 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 six months ended June 30, 2020, we used $87.4 million primarily to fund the Springbok Acquisition and $1.3 million to fund the capital commitments of the Joint Venture, partially offset by a $0.2 million cash distribution received in connection with the Joint Venture.

Financing Activities

Cash flows used in financing activities were $39.8 million for the six months ended June 30, 2021 compared to $50.0 million of cash flows provided by financing activities for the six months ended June 30, 2020. Cash flows used in financing activities for the six months ended June 30, 2021 consists of $29.7 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $13.1 million used to repay borrowings under out secured revolving credit facility, $1.1 million of restricted units repurchased for tax withholding, $0.2 million payment of loan origination costs and $0.2 million paid in connection with the redemption of Class B units, partially offset by $4.5 million of additional borrowings under our secured revolving credit facility. Cash flows provided by financing activities for the six months ended June 30, 2020 consists of $156.6 million of additional borrowings under our secured revolving credit facility and $73.6 million in proceeds from the underwritten public offering of 5,000,000 common units. Cash flows provided by financing activities for the six months ended June 30, 2020 were partially offset by $85.0 million used to repay borrowings under our secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units, $33.8 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units and $0.3 million paid in connection with the redemption of Class B units.

Table of Contents

Capital Expenditures

During the six months ended June 30, 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 six months ended June 30, 2020, we paid approximately $87.4 million primarily in connection with the Springbok Acquisition.

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 May 1, 2021 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $265.0 million.

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 June 30, 2021, we had outstanding borrowings of $162.9 million under the secured revolving credit facility and $102.1 million of available capacity. On July 1, 2021 we drew down $36.1 million on the senior secured revolving credit facility to fund the redemption of the Series A preferred units. As of July 30, 2021, we had outstanding borrowings of $199.0 million under the secured revolving credit facility and $66.0 million of available capacity.

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

Table of Contents

(no more than approximately 5% of estimated pre-tax distributable cash flow), and (ii) substantially all distributions (more than 95%) paid to our common unitholders will not be taxable dividend income through 2025.

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 have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our 2020 Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our 2020 Form 10-K. As of June 30, 2021, 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 to the contracts is an unrelated third party.

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

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

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts.

Table of Contents

Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. See Note 4—Derivatives to the unaudited interim condensed consolidated financial statements in Item 1 of this Quarterly Report for additional information regarding our commodity derivatives.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not 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 June 30, 2021, we had two 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 June 30, 2021, we had total borrowings outstanding under our secured revolving credit facility of $162.9 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 $1.6 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 92% of our outstanding balance as of June 30, 2021), at approximately 3.9% for the period ending on January 29, 2024. We use an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of our secured revolving credit facility from a floating to a fixed rate. For the three and six months ended June 30, 2021, we recognized a $0.05 million loss and $0.4 million gain on interest rate swaps, respectively, which are included in other income in the accompanying unaudited interim condensed consolidated statements of operations.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) 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 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”). Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that as of June 30, 2021, 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 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.

Table of Contents

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 June 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a description of the Partnership’s legal proceedings, see Note 14—Commitments and Contingencies to the unaudited interim condensed consolidated financial statements included in Part I of this Quarterly Report and incorporated by reference herein.

Item 1A. Risk Factors

In addition to the risks and uncertainties discussed in this Quarterly Report, particularly the risk factor disclosed below and those disclosed in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our 2020 Form 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

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

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

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

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

On May 17, 2021, we issued 998,854 common units to Springbok Energy Partners II Holdings, LLC in exchange for 998,854 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018 (the “Exchange Agreement”), by and among Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, the Kimbell Art Foundation, us, the General Partner, the Operating Company and the other holders of OpCo Common Units and Class B Units from time to time party thereto.

On May 25, 2021, we issued 2,169,348 common units to Buckhorn Resources GP, LLC, Buckhorn Minerals I GP, LP, Buckhorn Minerals I, LP, Buckhorn Minerals II, LP, Buckhorn Minerals III, LP, Buckhorn Minerals Ill-QP, LP,

Table of Contents

and Buckhorn Minerals IV, LP in exchange for 2,169,348 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement.

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

The following table summarizes our equity repurchase activity during the second quarter of 2021:


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)
April 1, 2021 - April 30, 2021	21,626	$	10.20	—	—
May 1, 2021 - May 31, 2021	—	$	—	—	—
June 1, 2021 - June 30, 2021	—	$	—	—	—

(1)

All of the common units shown above were withheld during the three months ended June 30, 2021 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 June 30, 2021, and currently do not have, a common unit repurchase program in place.

Table of Contents

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

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: August 5, 2021	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: August 5, 2021	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. senior Avg

Kimbell Royalty Partners (KRP) 10-Q2021 Q2 Quarterly report

Content analysis