Kimbell Royalty Partners, LP - Quarter Report: 2019 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2019 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 November 1, 2019, the registrant had outstanding 23,520,219 common units representing limited partner interests and 23,388,258 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	22
Item 3. Quantitative and Qualitative Disclosures About Market Risk	38
Item 4. Controls and Procedures	39


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	41
Item 1A. Risk Factors	41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 6. Exhibits	42
Signatures	43

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30,		December 31,
	2019		2018
ASSETS
Current assets
Cash and cash equivalents	$	20,297,982	$	15,773,987
Oil, natural gas and NGL receivables		16,934,026		18,809,170
Commodity derivative assets		2,380,629		2,981,117
Accounts receivable and other current assets		440,390		50,551
Total current assets		40,053,027		37,614,825
Property and equipment, net		1,202,434		429,602
Investment in affiliate (equity method)		2,885,037		—
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($299,613,448 and $280,304,353 excluded from depletion at September 30, 2019 and December 31, 2018, respectively)		987,942,123		818,594,943
Less: accumulated depreciation, depletion and impairment		(211,242,100)		(107,779,453)
Total oil and natural gas properties, net		776,700,023		710,815,490
Deposits on oil and natural gas properties		986,000		—
Right-of-use assets, net		3,466,101		—
Commodity derivative assets		969,062		1,246,829
Loan origination costs, net		2,483,443		3,178,627
Total assets	$	828,745,127	$	753,285,373

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	1,131,402	$	1,331,081
Other current liabilities		5,667,143		2,468,945
Total current liabilities		6,798,545		3,800,026
Operating lease liabilities		3,436,847		—
Long-term debt		91,261,477		87,309,544
Total liabilities		101,496,869		91,109,570
Commitments and contingencies (Note 15)
Mezzanine equity:
Series A preferred units (110,000 units issued and outstanding as of September 30, 2019 and December 31, 2018)		73,365,147		69,449,006
Unitholders' equity:
Common units (23,520,219 units issued and outstanding as of September 30, 2019 and 18,056,487 units issued and outstanding as of December 31, 2018)		341,969,430		299,821,901
Class B units (23,388,258 units issued and outstanding as of September 30, 2019 and 19,453,258 units issued and outstanding as of December 31, 2018)		1,169,413		972,663
Total unitholders' equity		343,138,843		300,794,564
Noncontrolling interest		310,744,268		291,932,233
Total equity		653,883,111		592,726,797
Total liabilities, mezzanine equity and unitholders' equity	$	828,745,127	$	753,285,373

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

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenue
Oil, natural gas and NGL revenues	$	29,531,138	$	21,085,377	$	80,278,506	$	42,741,233
Lease bonus and other income		940,898		358,215		2,313,548		1,124,949
Gain (loss) on commodity derivative instruments, net		2,506,815		(3,035,636)		270,607		(3,858,990)
Total revenues		32,978,851		18,407,956		82,862,661		40,007,192
Costs and expenses
Production and ad valorem taxes		2,236,405		1,410,335		5,757,742		3,031,732
Depreciation and depletion expense		15,098,107		7,607,137		37,690,558		15,494,439
Impairment of oil and natural gas properties		34,880,071		—		65,828,980		54,753,444
Marketing and other deductions		2,332,010		1,689,780		5,938,093		2,868,655
General and administrative expense		5,694,534		4,879,497		17,248,399		11,650,291
Total costs and expenses		60,241,127		15,586,749		132,463,772		87,798,561
Operating (loss) income		(27,262,276)		2,821,207		(49,601,111)		(47,791,369)
Other expense
Equity loss in affiliate		80,896		—		80,896		—
Interest expense		1,468,419		1,843,483		4,332,633		2,677,083
Net (loss) income before income taxes		(28,811,591)		977,724		(54,014,640)		(50,468,452)
Provision for income taxes		102,997		1,977,116		610,798		1,977,116
Net loss		(28,914,588)		(999,392)		(54,625,438)		(52,445,568)
Distribution and accretion on Series A preferred units		(3,469,584)		(2,840,456)		(10,408,752)		(2,840,456)
Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests		16,146,535		141,003		33,398,555		141,003
Distribution on Class B units		(23,414)		(12,953)		(71,042)		(12,953)
Net loss attributable to common units	$	(16,261,051)	$	(3,711,798)	$	(31,706,677)	$	(55,157,974)

Net loss attributable to common units
Basic	$	(0.73)	$	(0.15)	$	(1.53)	$	(2.91)
Diluted	$	(0.73)	$	(0.15)	$	(1.53)	$	(2.91)
Weighted average number of common units outstanding
Basic		22,399,748		24,079,289		20,715,633		18,962,446
Diluted		22,399,748		24,079,289		20,715,633		18,962,446

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

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)


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

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KIMBELL ROYALTY PARTNERS, LP

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

(Unaudited)


	Nine Months Ended September 30, 2018
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Balance at January 1, 2018		16,509,799	$	262,065,434		—	$	—	$	—	$	262,065,434
Distributions to unitholders		—		(6,061,123)		—		—		—		(6,061,123)
Restricted units granted, net of forfeitures		325,185		—		—		—		—		—
Unit-based compensation		—		668,934		—		—		—		668,934
Net loss		—		(52,824,471)		—		—		—		(52,824,471)
Balance at March 31, 2018		16,834,984		203,848,774		—		—		—		203,848,774
Distributions to unitholders		—		(7,070,693)		—		—		—		(7,070,693)
Restricted units granted, net of forfeitures		4,478		—		—		—		—		—
Unit-based compensation		—		723,039		—		—		—		723,039
Net income		—		1,378,295		—		—		—		1,378,295
Balance at June 30, 2018		16,839,462		198,879,415		—		—		—		198,879,415
Common units issued for acquisition		10,000,000		235,400,000		—		—		—		235,400,000
Recapitalization related to tax conversion		(12,953,258)		(209,591,880)		12,953,258		647,663		209,591,880		647,663
Distributions to unitholders		—		(11,540,969)		—		—		—		(11,540,969)
Unit-based compensation		—		751,074		—		—		—		751,074
Issuance of Series A preferred units		—		36,607,966		—		—		—		36,607,966
Distribution and accretion on Series A preferred units				(2,840,456)		—		—		—		(2,840,456)
Distribution on Class B units				(12,953)		—		—		—		(12,953)
Net income		—		(858,389)		—		—		(141,003)		(999,392)
Balance at September 30, 2018		13,886,204	$	246,793,808		12,953,258	$	647,663	$	209,450,877	$	456,892,348

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

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
	2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(54,625,438)	$	(52,445,568)
Adjustments to reconcile net loss to net cash provided by operating activities:
Provision for deferred income taxes		—		1,475,648
Depreciation and depletion expense		37,690,558		15,494,439
Impairment of oil and natural gas properties		65,828,980		54,753,444
Amortization of right-of-use assets		88,058		—
Amortization of loan origination costs		783,961		208,276
Equity loss in affiliate		80,896		—
Unit-based compensation		5,692,926		2,143,047
Loss on commodity derivative instruments, net of settlements		878,255		3,495,463
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		5,270,397		(8,781,555)
Accounts receivable and other current assets		(389,839)		(190,093)
Accounts payable		(399,679)		1,172,615
Other current liabilities		3,198,198		1,266,354
Operating lease liabilities		(117,312)		—
Net cash provided by operating activities		63,979,961		18,592,070
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(829,724)		(396,480)
Proceeds from sale of oil and natural gas properties		—		10,576,595
Purchase of oil and natural gas properties		(1,192,432)		(210,574,890)
Deposits on oil and natural gas properties		(986,000)		—
Investment in affiliate		(2,965,933)		—
Net cash used in investing activities		(5,974,089)		(200,394,775)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of Series A preferred units, net of issuance costs		—		103,359,603
Contributions from Class B unitholders		470,000		647,663
Redemption of Class B contributions on converted units		(73,250)		—
Issuance costs paid on Series A preferred units		(717,612)		—
Distributions to unitholders		(51,157,094)		(24,672,785)
Distributions on Series A preferred units		(5,775,000)		(705,834)
Distributions to Class B unitholders		(71,042)		—
Borrowings on long-term debt		3,951,933		124,336,547
Repayments on long-term debt		—		(6,870,596)
Payment of loan origination costs		(88,776)		(3,389,421)
Restricted units used for tax withholding		(21,036)		—
Net cash (used in) provided by financing activities		(53,481,877)		192,705,177
NET INCREASE IN CASH AND CASH EQUIVALENTS		4,523,995		10,902,472
CASH AND CASH EQUIVALENTS, beginning of period		15,773,987		5,625,495
CASH AND CASH EQUIVALENTS, end of period	$	20,297,982	$	16,527,967
Supplemental cash flow information:
Cash paid for interest	$	3,572,952	$	2,220,885
Non-cash investing and financing activities:
Right-of-use assets obtained in exchange for operating lease liabilities	$	3,554,159	$	—
Units issued in exchange for oil and natural gas properties	$	171,550,000	$	235,400,000
Distribution to Series A preferred unitholders in accounts payable	$	—	$	981,837
Non-cash deemed distribution to Series A preferred units	$	4,633,752	$	1,152,785
Distribution to Class B unitholders in accounts payable	$	—	$	12,953
Redemption of Class B contributions on converted units in accounts payable	$	200,000	$	—

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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP is a Delaware limited partnership formed 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, 2018, which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of the Partnership’s management, the unaudited interim condensed consolidated financial statements contain all adjustments necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP and all adjustments are of a normal recurring nature. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.

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

Segment Reporting

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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Restructuring, Tax Election and Related Transactions

On July 24, 2018, the Partnership entered into a Recapitalization Agreement (the "Recapitalization Agreement") with Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC (collectively, the “Haymaker Holders”), the Kimbell Art Foundation, Haymaker Resources, LP, the General Partner and the Operating Company pursuant to which (a) the Partnership's equity interest in the Operating Company was recapitalized into 13,886,204 newly issued common units of the Operating Company ("OpCo Common Units") and 110,000 newly issued Series A Cumulative Convertible Preferred Units in the Operating Company and (b) the 10,000,000 and 2,953,258 common units held by the Haymaker Holders and the Kimbell Art Foundation, respectively, were exchanged for (i) 10,000,000 and 2,953,258 newly issued Class B common units representing limited partner interests of the Partnership ("Class B Units"), respectively, and (ii) 10,000,000 and 2,953,258 newly issued OpCo Common Units, respectively. The Class B Units and OpCo Common Units are exchangeable together into an equal number of common units of the Partnership.

In May 2018, the General Partner’s Board of Directors (the “Board of Directors”) unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election (the “Tax Election”). The Tax Election became effective on September 24, 2018.

For each Class B Unit issued, five 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 (as defined in Note 7—Long-Term Debt) but prior to distributions on the common units.

Following the effectiveness of the Tax Election and the completion of the related transactions, the Partnership’s royalty and minerals business continues to be conducted through the Operating Company, which is taxed as a partnership for federal and state income tax purposes. The Operating Company passes income to the noncontrolling interest and the Partnership, which is treated as a corporation for federal and state income tax purposes. As of November 1, 2019, 50.1% of the OpCo Common Units were held by the Partnership and 49.9% were held by third parties.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the nine months ended September 30, 2019, other than those discussed below in Recently Adopted Accounting Pronouncements.

Reclassification of Prior Period Presentation

Certain prior period amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on previously reported net income (loss), total cash flows from operations or working capital.

New Accounting Pronouncements

Recently Adopted Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016‑02, “Leases.” ASU 2016‑02 requires the recognition of right-of-use (“ROU”) assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year, with early adoption permitted. The Partnership adopted this update using the modified retrospective

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

approach, effective January 1, 2019. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations for the three and nine months ended September 30, 2019.

The Partnership evaluated whether its contractual arrangements contain leases at the inception of such arrangements. Specifically, the Partnership considered whether it can control the underlying asset and have the right to obtain substantially all of the economic benefits or outputs from the asset. Substantially all of the Partnerships leases are long-term operating leases with fixed payment terms and will terminate in October 2028. The Partnership’s ROU operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying unaudited condensed consolidated balance sheet as of September 30, 2019. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of September 30, 2019 was 9.59 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the Amended Credit Agreement, as defined in Note 7—Long-Term Debt, as of January 1, 2019. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the nine months ended September 30, 2019.

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

Currently, the most substantial contractual arrangement that the Partnership has classified as an operating lease is the main office space used for operations. In July 2019, the Partnership became the lessee in several other related lease agreements for additional office space. In addition, the Partnership was involved in the construction and design of the underlying assets. The underlying assets were capitalized in July 2019 upon commencement of the lease.

Future minimum lease commitments as of September 30, 2019 were as follows:


			Remainder of
	Total		2019		2020		2021		2022		2023		Thereafter
Operating leases	$	4,736,830	$	116,761	$	472,737	$	478,428	$	478,837	$	479,796	$	2,710,271
Less: Imputed Interest		(1,299,983)
Total	$	3,436,847

In July 2018, the FASB issued ASU 2018-09, “Codification Improvements.” This update provides clarification and corrects unintended application of the guidance in various sections. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations for the three and nine months ended September 30, 2019.

In July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842, Leases.” This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations for the three and nine months ended September 30, 2019.

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Accounting Pronouncements Not Yet Adopted

In August 2018, the FASB issued ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement.” This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

NOTE 3—ACQUISITIONS, JOINT VENUTURES AND DIVESTITURES

Acquisitions

On March 25, 2019, the Partnership acquired all of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC that own oil and natural gas mineral and royalty interests (the “Phillips Acquisition”). The aggregate consideration for the Phillips Acquisition consisted of 9,400,000 OpCo Common Units and an equal number of Class B Units, valued at approximately $171.6 million based on the closing price of the Partnership’s common units of $18.25 on March 25, 2019. The assets acquired in the Phillips Acquisition consisted of approximately 866,528 gross acres and 12,210 net royalty acres.

On July 12, 2018, the Partnership completed the acquisition of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (the “Haymaker Acquisition”) in a transaction valued at approximately $444.0 million. The purchase price for the Haymaker Acquisition was comprised of (i) net cash consideration of approximately $208.6 million and (ii) 10,000,000 common units of the Partnership, valued at approximately $235.4 million based on the closing price of the Partnership’s common units of $23.54 on July 12, 2018. The Partnership funded the cash consideration with borrowings under the Amended Credit Agreement and net proceeds from the Preferred Unit Transaction (as defined in Note 8 – Preferred Units). The assets acquired in the Haymaker Acquisition consisted of approximately 5.4 million gross acres and 43,000 net royalty acres.

The following unaudited pro forma results of operations reflect the Partnership’s results as if the Haymaker Acquisition, the acquisition of certain overriding royalty, royalty and other mineral interests from Rivercrest Capital Partners LP, the Kimbell Art Foundation and Cupola Royalty Direct, LLC, as well as all of the equity interests of a subsidiary of Rivercrest Royalties Holdings II, LLC (the “Dropdown”), and the Phillips Acquisition had occurred on January 1, 2018. In the Partnership’s opinion, all significant adjustments necessary to reflect the effects of the Haymaker Acquisition, Dropdown and Phillips Acquisition have been made. Pro forma data may not be indicative of the results that would have been obtained had these events occurred at the beginning of the periods presented, nor is it intended to be a projection of future results.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Total revenues	$	32,978,851	$	30,506,261	$	87,871,247	$	91,943,767
Net loss attributable to common units	$	(16,261,051)	$	(1,694,292)	$	(27,233,939)	$	(17,260,464)

Net loss attributable to common units
Basic	$	(0.73)	$	(0.08)	$	(1.31)	$	(0.83)
Diluted	$	(0.73)	$	(0.08)	$	(1.31)	$	(0.83)

On September 20, 2019, the Partnership agreed to acquire various mineral and royalty interests in Oklahoma for an aggregate purchase price of approximately $9.9 million. The acquisition closed on November 6, 2019. The Partnership funded the payment of the purchase price with borrowings under its secured revolving credit facility. In connection with the execution of the purchase agreement, the Partnership paid a deposit of approximately $1.0 million on the purchase price. This deposit is included in deposits on oil and natural gas properties on the accompanying condensed consolidated balance sheet. See Note 16 – Subsequent Events for details on the closing of this acquisition.

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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. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed $15.0 million. The Joint Venture will be managed by Springbok Operating Company, LLC. The purpose of the Joint Venture will be 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 will utilize the equity method of accounting for its investment in the Joint Venture. As of September 30, 2019, the Partnership has paid approximately $3.0 million under its capital commitment.

Divestitures

In May 2018, the Partnership executed two purchase and sale agreements to sell a small portion of its Delaware Basin acreage for $10.6 million, which was recorded as a reduction in the full-cost pool, with no gain or loss recorded on the sale. At the time of the divestiture, the sales represented approximately 29 barrels of equivalent (“Boe”) per day of production, less than 0.8% of total production and 59 net royalty acres, approximately 0.08% of total net royalty acres.

NOTE 4—DERIVATIVES

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty.

As of September 30, 2019, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The Partnership hedges its daily production based on the amount of debt and/or preferred equity as a percent of its enterprise value. This amount constitutes approximately 19% of daily oil and natural gas production.

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Beginning fair value of commodity derivative instruments	$	1,665,887		(1,000,359)	$	4,227,946	$	(318,829)
Gain (loss) on commodity derivative instruments		2,506,815		(3,035,636)		270,607		(3,858,990)
Net cash (received) paid on settlements of derivative instruments		(823,011)		221,703		(1,148,862)		363,527
Ending fair value of commodity derivative instruments	$	3,349,691	$	(3,814,292)	$	3,349,691	$	(3,814,292)

The following table presents the fair value of the Partnership’s derivative contracts as of September 30, 2019 and December 31, 2018:


		September 30,		December 31,
Classification	Balance Sheet Location	2019		2018
Assets:
Current asset	Commodity derivative assets	$	2,380,629	$	2,981,117
Long-term asset	Commodity derivative assets		969,062		1,246,829
Liabilities:
Current liability	Commodity derivative liabilities		—		—
Long-term liability	Commodity derivative liabilities		—		—
		$	3,349,691	$	4,227,946

As of September 30, 2019, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps


	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High
September 2019 - December 2019	74,908	$	61.47	$	53.07	$	63.47
January 2020 - December 2020	224,356	$	55.48	$	50.45	$	61.43
January 2021 - June 2021	178,231	$	53.58	$	50.79	$	56.10

Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
October 2019 - December 2019	972,716	$	2.74	$	2.74	$	2.76
January 2020 - December 2020	3,582,862	$	2.64	$	2.51	$	2.94
January 2021 - June 2021	2,610,021	$	2.52	$	2.33	$	2.85

NOTE 5—FAIR VALUE MEASUREMENTS

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the unaudited condensed consolidated balance sheets approximated fair value as of September 30, 2019 and December 31, 2018. As a result, these financial assets and liabilities are not discussed below.

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

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

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and nine months ended September 30, 2019 and 2018.

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

NOTE 6—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:


	September 30,		December 31,
	2019		2018
Oil and natural gas properties
Proved properties	$	688,328,675	$	538,290,590
Unevaluated properties		299,613,448		280,304,353
Less: accumulated depreciation, depletion and impairment		(211,242,100)		(107,779,453)
Total oil and natural gas properties	$	776,700,023	$	710,815,490

Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within five years of the date of acquisition of the unevaluated properties.

The Partnership assesses all items classified as unevaluated property on an annual 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: 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. 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.

The Partnership recorded an impairment on its oil and natural gas properties of $34.9 million for the three months ended September 30, 2019 primarily as a result of a decline in the 12-month average price of oil and natural gas. No impairment expense was recorded for the three months ended September 30, 2018. The Partnership recorded an impairment on its oil and natural gas properties of $65.8 million and $54.8 million during the nine months ended September 30, 2019 and 2018, respectively, as a result of its quarterly full cost ceiling analysis and due to a decline in the 12-month average price of oil and natural gas. As of September 30, 2019, the 12-month average prices of oil and natural gas were $57.77 per Bbl of oil and $2.87 per Mcf of natural gas. These prices represent an 11.9% and 7.4% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2018, which were $65.56 per Bbl of oil and $3.10 per Mcf of natural gas.

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NOTE 7—LONG-TERM DEBT

In connection with its initial public offering (“IPO”), 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, in connection with the Haymaker Acquisition, the Partnership entered into an amendment (the “Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement (the 2017 Credit Agreement as amended by the Credit Agreement Amendment, the “Amended Credit Agreement”), by and among the Partnership, certain subsidiaries of the Partnership, as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto.

The Credit Agreement Amendment amends the 2017 Credit Agreement to provide for, among other things, (i) the addition of the subsidiaries the Partnership acquired in the Haymaker Acquisition, as well as the Operating Company, as guarantors under the Amended Credit Agreement, (ii) limitations on the Partnership’s ability to incur certain debt or issue preferred equity, (iii) limitations on redemptions of the Series A Cumulative Convertible Preferred Units (“Series A Preferred Units”) and the ability of the Partnership and the restricted subsidiaries of the Partnership to make distributions and other restricted payments, in each case, unless certain conditions are satisfied, (iv) increased limitations on the Partnership’s ability to dispose of certain assets or encumber certain assets, (v) a decrease in the applicable margin under the 2017 Credit Agreement, which varies based upon the level of borrowing base usage, by 0.25% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 2.00% to 3.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement) and (vi) the addition of certain restrictions on the Partnership’s and the Operating Company’s ability to take certain actions or amend their organizational documents.

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, 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 secured revolving credit facility) of not more than 4.0 to 1.0 and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The 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.

The Credit Agreement Amendment increased commitments under the Amended Credit Agreement from $50.0 million to $200.0 million. Under the Amended Credit Agreement, availability under the secured revolving credit facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base under the Amended Credit Agreement was set at $200.0 million. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased to $500.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The borrowing base will be redetermined semiannually on May 1 and November 1 of each year based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the Partnership’s wholly owned subsidiaries. In connection with the May redetermination, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million and the borrowing base was increased from $200.0 million to $300.0 million. The November borrowing base redetermination is currently being conducted and is expected to be finalized by the end of November 2019. The secured revolving credit facility matures on February 8, 2022.

During the three and nine months ended September 30, 2019, the Partnership borrowed an additional $4.0 million under the secured revolving credit facility. As of September 30, 2019, the Partnership’s outstanding balance was $91.3 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of September 30, 2019.

As of September 30, 2019, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% or Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the nine

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months ended September 30, 2019, the weighted average interest rate on the Partnership’s outstanding borrowings was 4.68%.

NOTE 8—PREFERRED UNITS

In July 2018, in connection with the closing of the Haymaker Acquisition, 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 (the “Preferred Unit Transaction”). 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 the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A Preferred Units.

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

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

The following table summarizes the changes in the number of the Series A Preferred Units:


		Series A
		Preferred Units
Balance at December 31, 2018		110,000
Balance at September 30, 2019		110,000

NOTE 9—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has limited partner units. As of September 30, 2019, the Partnership had a total of 23,520,219 common units issued and outstanding and 23,388,258 Class B Units outstanding.

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


		Common Units
Balance at December 31, 2018		18,056,487
Conversion of Class B Units		5,465,000
Restricted units used for tax withholding		(1,268)
Balance at September 30, 2019		23,520,219

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The following table presents information regarding the common unit cash distributions approved by the Board of Directors for the periods presented:


	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2019	$	0.37	April 26, 2019	May 6, 2019	May 13, 2019
Q2 2019	$	0.39	July 26, 2019	August 5, 2019	August 12, 2019
Q3 2019	$	0.42	October 25, 2019	November 4, 2019	November 11, 2019

Q1 2018	$	0.42	April 27, 2018	May 7, 2018	May 14, 2018
Q2 2018	$	0.43	July 27, 2018	August 6, 2018	August 13, 2018
Q3 2018	$	0.45	October 26, 2018	November 5, 2018	November 12, 2018

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


		Class B Units
Balance at December 31, 2018		19,453,258
Class B Units issued for Phillips Acquisition		9,400,000
Conversion of Class B Units		(5,465,000)
Balance at September 30, 2019		23,388,258

Holders of the Class B Units, are entitled to receive cash distributions equal to 2% 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 10—EARNINGS (LOSS) PER UNIT

Basic earnings (loss) per unit (“EPU”) is calculated by dividing net income (loss) attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested restricted units granted under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) for its employees, directors and consultants and potential conversion of Class B Units.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net loss attributable to common units	$	(16,261,051)	$	(3,711,798)	$	(31,706,677)	$	(55,157,974)

Weighted average number of common units outstanding:
Basic		22,399,748		24,079,289		20,715,633		18,962,446
Effect of dilutive securities:
Series A preferred units		—		—		—		—
Class B units		—		—		—		—
Restricted units		—		—		—		—
Diluted		22,399,748		24,079,289		20,715,633		18,962,446

Net loss attributable to common units
Basic	$	(0.73)	$	(0.15)	$	(1.53)	$	(2.91)
Diluted	$	(0.73)	$	(0.15)	$	(1.53)	$	(2.91)

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The calculation of diluted net loss per unit for the three and nine months ended September 30, 2019 excludes the conversion of Series A Preferred Units to common units, the conversion of Class B Units to common units and 975,540 of unvested restricted units because their inclusion in the calculation would be anti-dilutive. The calculation of diluted net loss per unit for the three and nine months ended September 30, 2018 excludes the conversion of Series A Preferred Units to common units, the conversion of Class B Units to common units and 437,641 unvested restricted units because their inclusion in the calculation would be anti-dilutive.

NOTE 11—UNIT-BASED COMPENSATION

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

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, 2018	1,157,924	$	18.054	2.696 years
Vesting	(182,384)		18.737	—
Unvested at September 30, 2019	975,540	$	17.926	1.546 years

NOTE 12—INCOME TAXES

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

Prior to September 24, 2018, the effective date of the Partnership’s change in income tax status, the Partnership was organized as a pass-through entity for income tax purposes. As a result, the Partnership’s partners were responsible for federal income taxes on their share of the Partnership’s taxable income with the exception of any entity-level income taxes such as the Texas Margins Tax. The Partnership recorded a provision for income taxes of $0.1 million and $0.6 million for the three and nine months ended September 30, 2019, respectively. The tax payment made by the Partnership for the three and nine months ended September 30, 2019 was generated by a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker Acquisition.

NOTE 13—RELATED PARTY TRANSACTIONS

In connection with the IPO, the Partnership entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), Steward Royalties, LLC (“Steward Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(“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 will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders. During the three and nine months ended September 30, 2019, no monthly services fee was paid to BJF Royalties or Steward Royalties. During the three months ended September 30, 2019, the Partnership made payments to Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $131,714, $30,000, $81,918 and $124,576, respectively. During the nine months ended September 30, 2019, the Partnership made payments to Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $395,142, $90,000, $245,754 and $373,728, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s LTIP.

NOTE 14—ADMINISTRATIVE SERVICES

Management Services Agreement

The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business efforts. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the Board of Directors and their affiliated entities. See Note 13―Related Party Transactions.

Transition Services Agreement

On March 25, 2019, in connection with the Phillips Acquisition, the Partnership entered into a Transition Services Agreement (the “Transition Services Agreement”) with Fortis Administrative Services, LLC (“Fortis”). Pursuant to the Transition Services Agreement, Fortis provided certain administrative services and accounting assistance on a transitional basis for total compensation of $300,000 from April 1, 2019 through June 1, 2019, at which point, the Transition Services Agreement was terminated.

NOTE 15—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. The Partnership is currently assessing such a situation relating to certain non-producing acreage in its portfolio, the resolution of which is not expected to have a material impact on the Partnership’s condensed consolidated financial statements, and no amounts have been accrued as of September 30, 2019.

NOTE 16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to September 30, 2019 in the preparation of its condensed consolidated financial statements.

On November 6, 2019, the Partnership completed the acquisition of various mineral and royalty interests in Oklahoma in a transaction valued at $9.9 million. The assets acquired consist of approximately 279,680 gross acres and 186 net royalty acres.

On November 6, 2019, the Partnership paid a quarterly cash distribution on the Series A Preferred Units of $1.9 million for the quarter ended September 30, 2019.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

the Haymaker Acquisition. Under the limited liability company agreement of the Operating Company, the Partnership is not reimbursed by the Operating Company for federal income taxes paid by the Partnership.

On November 8, 2019, 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 approximately $23,388 for the quarter ended September 30, 2019.

On October 25, 2019 the Board of Directors declared a quarterly cash distribution of $0.42 per common unit for the quarter ended September 30, 2019. The distribution will be paid on November 11, 2019 to common unitholders of record as of the close of business on November 4, 2019.

NOTE 17—CORRECTION OF IMMATERIAL ERRORS

In connection with the preparation of the Partnership’s condensed consolidated financial statements for the three and nine months ended September 30, 2019, the Partnership identified immaterial errors related to the classification of distributions made to the holders of OpCo Common Units in prior interim and annual periods. In accordance with SAB No. 99, “Materiality,” and SAB No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” the Partnership evaluated the errors and determined that the related impact was not material to its financial statements for any prior annual or interim period. The Partnership has adjusted its consolidated balance sheet at December 31, 2018, its condensed consolidated balance sheets at March 31, 2019 and June 30, 2019, its consolidated statement of changes in unitholders’ equity for the year ended December 31, 2018 and its condensed consolidated statements of changes in unitholders’ equity for the three months ended March 31, 2019 and the six months ended June 30, 2019. The Partnership will also correct previously reported financial information for such immaterial errors in its future filings, as applicable.

The effects of the adjustment on the individual line items within the Partnership’s consolidated balance sheet at December 31, 2018 and its condensed consolidated balance sheets at March 31, 2019 and June 30, 2019 are as follows:


	December 31, 2018
	As Reported		Adjustments		As Adjusted
Common units	$	293,992,935	$	5,828,966	$	299,821,901
Noncontrolling interest	$	297,761,199	$	(5,828,966)	$	291,932,233

	March 31, 2019
	As Reported		Adjustments		As Adjusted
Common units	$	300,579,597	$	13,034,703	$	313,614,300
Noncontrolling interest	$	440,652,288	$	(13,034,703)	$	427,617,585

	June 30, 2019
	As Reported		Adjustments		As Adjusted
Common units	$	337,096,345	$	21,846,010	$	358,942,355
Noncontrolling interest	$	365,011,777	$	(21,846,010)	$	343,165,767

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The effects of the adjustment on the individual line items within the Partnership’s consolidated statement of changes in unitholders’ equity for the year ended December 31, 2018 are as follows:


	As Reported
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	(38,303,043)		—	$	—	$	—	$	(38,303,043)
Balance at December 31, 2018		18,056,487	$	293,992,935		19,453,258	$	972,663	$	297,761,199	$	592,726,797

	Adjustments
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	5,828,966		—	$	—	$	(5,828,966)	$	—

	As Adjusted
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	(32,474,077)		—	$	—	$	(5,828,966)	$	(38,303,043)
Balance at December 31, 2018		18,056,487	$	299,821,901		19,453,258	$	972,663	$	291,932,233	$	592,726,797

The effects of the adjustment on the individual line items within the Partnership’s condensed consolidated statement of changes in unitholders’ equity for the three months ended March 31, 2019 are as follows:


	As Reported
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	(15,003,898)		—	$	—	$	—	$	(15,003,898)
Balance at March 31, 2019		19,495,403	$	300,579,597		27,414,342	$	1,370,717	$	440,652,288	$	742,602,602

	Adjustments
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	7,205,737		—	$	—	$	(7,205,737)	$	—

	As Adjusted
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	(7,798,161)		—	$	—	$	(7,205,737)	$	(15,003,898)
Balance at March 31, 2019		19,495,403	$	313,614,300		27,414,342	$	1,370,717	$	427,617,585	$	742,602,602

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The effects of the adjustment on the individual line items within the Partnership’s condensed consolidated statement of changes in unitholders’ equity for the six months ended June 30, 2019 are as follows:


	As Reported
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	(17,356,606)		—	$	—	$	—	$	(17,356,606)
Balance at June 30, 2019		23,094,135	$	337,096,345		23,814,342	$	1,190,717	$	365,011,777	$	703,298,839

	Adjustments
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	8,811,307		—	$	—	$	(8,811,307)	$	—

	As Adjusted
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Distributions to unitholders		—	$	(8,545,299)		—	$	—	$	(8,811,307)	$	(17,356,606)
Balance at June 30, 2019		23,094,135	$	358,942,355		23,814,342	$	1,190,717	$	343,165,767	$	703,298,839

Also in connection with the preparation of the Partnership’s condensed consolidated financial statements for the three and nine months ended September 30, 2019, the Partnership identified immaterial errors related to the captions on its condensed consolidated statements of operations for the three and nine months ended September 30, 2018 and consolidated statement of operations for the year ended December 31, 2018. In accordance with SAB No. 99, “Materiality,” and SAB No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” the Partnership evaluated the errors and determined that the related impact was not material to its financial statements for any prior annual or interim period. The Partnership has adjusted the captions on its condensed consolidated statements of operations for the three and nine months ended September 30, 2018 and consolidated statement of operations for the year ended December 31, 2018. The Partnership will also correct previously reported financial information for such immaterial errors in its future filings, as applicable.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The effects of the reclassification on the individual line items within the Partnership’s condensed consolidated statements of operations for the three and nine months ended September 30, 2018 are as follows:


	As Reported
	Three Months Ended September 30,		Nine Months Ended September 30,
	2018		2018
Net loss before Series A preferred unit distribution and accretion	$	(999,392)	$	(52,445,568)
Distribution and accretion on Series A preferred units		(2,840,456)		(2,840,456)
Net loss		(3,839,848)		(55,286,024)
Net loss attributable to noncontrolling interests		(141,003)		(141,003)
Net loss attributable to Kimbell Royalty Partners LP		(3,698,845)		(55,145,021)
Distribution on Class B units		(12,953)		(12,953)
Net loss attributable to common units	$	(3,711,798)	$	(55,157,974)

	As Corrected
	Three Months Ended September 30,		Nine Months Ended September 30,
	2018		2018
Net loss	$	(999,392)	$	(52,445,568)
Distribution and accretion on Series A preferred units		(2,840,456)		(2,840,456)
Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests		141,003		141,003
Distribution on Class B units		(12,953)		(12,953)
Net loss attributable to common units	$	(3,711,798)	$	(55,157,974)

The effects of the reclassification on the individual line items within the Partnership’s consolidated statement of operations for the year ended December 31, 2018 are as follows:


	As Reported
	Year Ended December 31,
	2018
Net loss before Series A preferred unit distribution and accretion	$	(52,282,223)
Distribution and accretion on Series A preferred units		(6,310,040)
Net loss		(58,592,263)
Net loss attributable to noncontrolling interests		(1,855,681)
Net loss attributable to Kimbell Royalty Partners LP		(56,736,582)
Distribution on Class B units		(30,967)
Net loss attributable to common units	$	(56,767,549)

	As Corrected
	Year Ended December 31,
	2018
Net loss	$	(52,282,223)
Distribution and accretion on Series A preferred units		(6,310,040)
Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests		1,855,681
Distribution on Class B units		(30,967)
Net loss attributable to common units	$	(56,767,549)

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

The following discussion and analysis of financial condition and results of operations should be read together in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10‑Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”).

On February 8, 2017, Kimbell Royalty Partners, LP (the “Partnership,” “we” or “us”) completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests. The mineral and royalty interests comprising our initial assets were contributed to us by certain entities and individuals (the “Contributing Parties”), including certain affiliates of our founders (our “Sponsors”), at the closing of our IPO.

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.

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,” “forecast,” “predict,” “strategy,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “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 identify, complete and integrate acquisitions of assets or businesses;

the effect of our Tax Election (as defined below) or our Restructuring (as defined below) on our customer relationships, operating results and business generally;

the failure to realize the anticipated benefits of our Tax Election or Restructuring;

our ability to execute our business strategies;

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

the level of production on our properties;

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

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

general economic, business or industry conditions;

competition in the oil and natural gas industry;

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;

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

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

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

the availability of transportation facilities;

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

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

future operating results;

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

operating hazards faced by the operators of our properties;

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

certain factors discussed elsewhere in this 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.

As of September 30, 2019, we owned mineral and royalty interests in approximately 8.7 million gross acres and overriding royalty interests in approximately 4.3 million gross acres, with approximately 48% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of September 30, 2019, 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 92,000 gross producing wells, including over 40,000 wells in the Permian Basin.

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The following table summarizes our ownership in United States basins and producing regions, information about the wells in which we have a mineral or royalty interest and the number of active rigs operating on our acreage as of September 30, 2019:


			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	Active Rigs
Permian Basin	2,615,262	23,536	1,667	1,374	40,191	31
Mid‑Continent	3,589,116	40,550	1,927	1,151	10,115	13
Haynesville	745,745	7,058	4,179	1,288	8,460	15
Appalachia	721,656	23,074	1,912	883	2,985	2
Bakken	1,555,557	5,959	500	426	3,801	12
Eagle Ford	532,142	6,282	1,382	1,080	2,394	4
Rockies	46,328	829	485	254	12,044	5
Other	3,222,614	36,829	2,786	1,518	12,921	—
Total	13,028,420	144,117	14,838	7,974	92,911	82

(1)

"Btu-equivalent" production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of "oil equivalent," which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read "Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves" in our Annual Report on Form 10-K for the year ended December 31, 2018.

(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.

Recent Developments

Acquisitions

On September 20, 2019, we agreed to acquire various mineral and royalty interests in Oklahoma for an aggregate purchase price of approximately $9.9 million. The acquisition closed on November 6, 2019. We funded the payment of the purchase price with borrowings under our secured revolving credit facility. In connection with the execution of the purchase agreement, we paid a deposit of approximately $1.0 million on the purchase price. The assets acquired consist of approximately 279,680 gross acres and 186 net royalty acres.

Transactions in Common Units

On July 29, 2019, Haymaker Minerals & Royalties, LLC exchanged 400,000 common units of the Operating Company (“OpCo Common Units”) and Class B common units representing limited partner interests in us (“Class B Units”), together, for an equal number of our common units.

On September 19, 2019, Haymaker Management, LLC exchanged 26,084 OpCo Common Units and Class B Units, together, for an equal number of our common units.

Third Quarter Distributions

On November 6, 2019, we paid a quarterly cash distribution on the Series A Preferred Units of $1.9 million for the quarter ended September 30, 2019.

On November 8, 2019, the Operating Company paid a quarterly cash distribution of $0.428494 to holders of OpCo Common Units. As to the Partnership, $0.008494 of the distribution corresponds to a tax payment made by us from cash reserves in the third quarter of 2019. The third quarter 2019 tax payment made by us was generated by a gross income allocation related to the Series A Preferred Units, which were issued in connection with the acquisition of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (the “Haymaker Acquisition”). Under the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us.

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On November 8, 2019, we paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution (as defined below), resulting in a total quarterly distribution of approximately $23,388 for the quarter ended September 30, 2019.

On October 25, 2019 the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.42 per common unit for the quarter ended September 30, 2019. The distribution will be paid on November 11, 2019 to common unitholders of record as of the close of business on November 4, 2019.

Business Environment

Commodity Prices and Demand

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


	Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
	High		Low		High		Low
Oil ($/Bbl)	$	66.24	$	46.31	$	77.41	$	59.20
Natural gas ($/MMBtu)	$	4.25	$	2.02	$	6.24	$	2.49

On October 28, 2019, the West Texas Intermediate posted price for crude oil was $55.60 per Bbl and the Henry Hub spot market price of natural gas was $2.49 per MMBtu.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Oil ($/Bbl)	$	56.34	$	69.69	$	56.75	$	66.93
Natural gas ($/MMBtu)	$	2.38	$	2.93	$	2.62	$	2.95

Rig Count

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

The Baker Hughes United States Rotary Rig count decreased by 18.4% from 1,054 active rigs as of September 30, 2018 to 860 active rigs as of September 30, 2019.

We own mineral and royalty interests in 28 states. According to the Baker Hughes United States Rotary Rig count, rig activity in the 28 states in which we own mineral and royalty interests included 851 active rigs as of September 30, 2019 compared to 1,048 active rigs as of September 30, 2018.

The active rig count across our acreage as of September 30, 2019 decreased by 7.9% to 82 active rigs compared to 89 active rigs at June 30, 2019. The 82 active rig count across our acreage as of September 30, 2019 increased by 15.5% compared to the 71 active rigs as of September 30, 2018, primarily due to the additional mineral and royalty interests we acquired in connection with the acquisition of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC (the “Phillips Acquisition”) in the first quarter of 2019, as well as the acquisition of certain overriding royalty, royalty and other mineral interests from Rivercrest Capital Partners LP, the Kimbell Art Foundation, and Cupola Royalty Direct, LLC, as well as all of the equity interests of a subsidiary of Rivercrest Royalties Holdings II, LLC (the “Dropdown”), in the fourth quarter of 2018.

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

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may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Royalty income
Oil sales	54	%	53	%	53	%	57	%
Natural gas sales	36	%	33	%	36	%	28	%
NGL sales	7	%	12	%	9	%	12	%
Lease bonus and other income	3	%	2	%	2	%	3	%
	100	%	100	%	100	%	100	%

We entered into oil and natural gas commodity derivative agreements with Frost Bank, beginning January 1, 2018 which extends through June 2021, 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.

Non‑GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution

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

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

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Reconciliation of net loss to Adjusted EBITDA:
Net loss	$	(28,914,588)	$	(999,392)	$	(54,625,438)	$	(52,445,568)
Depreciation and depletion expense		15,098,107		7,607,137		37,690,558		15,494,439
Interest expense		1,468,419		1,843,483		4,332,633		2,677,083
Provision for income taxes		102,997		1,977,116		610,798		1,977,116
EBITDA		(12,245,065)		10,428,344		(11,991,449)		(32,296,930)
Impairment of oil and natural gas properties		34,880,071		—		65,828,980		54,753,444
Transaction costs		—		—		—		1,188,967
Unit‑based compensation		1,809,752		751,074		5,692,926		2,143,047
(Gain) loss on commodity derivative instruments, net of settlements		(1,683,804)		2,813,933		878,255		3,495,463
Consolidated Adjusted EBITDA		22,760,954		13,993,351		60,408,712		29,283,991
Adjusted EBITDA attributable to noncontrolling interest		(11,348,462)		(6,753,469)		(31,696,443)		(6,753,469)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		11,412,492		7,239,882		28,712,269		22,530,522
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		611,885		643,309		1,819,003		1,620,796
Cash distributions on Series A preferred units		965,208		365,184		2,712,948		365,184
Cash income tax expense		147,000		—		651,000		—
Distributions on Class B units		23,414		12,953		71,042		12,953
Cash reserves		(147,000)		—		(651,000)		—
Cash available for distribution on common units	$	9,811,985	$	6,218,436	$	24,109,276	$	20,531,589

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	24,835,447	$	684,990	$	63,979,961	$	18,592,070
Interest expense		1,468,419		1,843,483		4,332,633		2,677,083
Provision for income taxes		102,997		501,468		610,798		501,468
Impairment of oil and natural gas properties		(34,880,071)		—		(65,828,980)		(54,753,444)
Amortization of right-of-use assets		(65,480)		—		(88,058)		—
Amortization of loan origination costs		(265,812)		(177,026)		(783,961)		(208,276)
Equity loss in affiliate		(80,896)		—		(80,896)		—
Unit-based compensation		(1,809,752)		(751,074)		(5,692,926)		(2,143,047)
Gain (loss) on commodity derivative instruments, net of settlements		1,683,804		(2,813,933)		(878,255)		(3,495,463)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(1,937,752)		8,976,629		(5,270,397)		8,781,555
Accounts receivable and other current assets		64,269		200,125		389,839		190,093
Accounts payable		10,991		3,749,971		399,679		(1,172,615)
Other current liabilities		(1,461,535)		(1,786,289)		(3,198,198)		(1,266,354)
Operating lease liabilities		90,306		—		117,312		—
EBITDA		(12,245,065)		10,428,344		(11,991,449)		(32,296,930)
Add:
Impairment of oil and natural gas properties		34,880,071		—		65,828,980		54,753,444
Transaction costs		—		—		—		1,188,967
Unit‑based compensation		1,809,752		751,074		5,692,926		2,143,047
(Gain) loss on commodity derivative instruments, net of settlements		(1,683,804)		2,813,933		878,255		3,495,463
Consolidated Adjusted EBITDA		22,760,954		13,993,351		60,408,712		29,283,991
Adjusted EBITDA attributable to noncontrolling interest		(11,348,462)		(513,851)		(31,696,443)		(513,851)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP	$	11,412,492	$	13,479,500	$	28,712,269	$	28,770,140

Factors Affecting the Comparability of Our Results to the 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.

Restructuring, Tax Election and Related Transactions

On July 24, 2018, we entered into a Recapitalization Agreement (the “Recapitalization Agreement”) with Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC (collectively, the “Haymaker Holders”), the Kimbell Art Foundation, Haymaker Resources, LP, the General Partner and the Operating Company pursuant to which (a) our equity interest in the Operating Company was recapitalized into 13,886,204 newly issued OpCo Common Units of the Operating Company and 110,000 newly issued Series A Preferred Cumulative Convertible Units of the Operating Company and (b) the 10,000,000 and 2,953,258 common units held by the Haymaker Holders and the Kimbell Art Foundation, respectively, were exchanged for (i) 10,000,000 and 2,953,258 newly issued Class B Units, respectively, and (ii) 10,000,000 and 2,953,258 newly issued OpCo Common Units, respectively. The Class B Units and OpCo Common Units are exchangeable together into an equal number of our common units.

In May 2018, the Board of Directors unanimously approved a change of our federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election (the “Tax Election”). The Tax Election became effective on September 24, 2018.

For each Class B Unit issued, five cents has been paid to us 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

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respective Class B Contribution, subsequent to distributions on the Series A Preferred Units but prior to distributions on the common units.

Following the effectiveness of the Tax Election and the completion of the related transactions, our royalty and minerals business continues to be conducted through the Operating Company, which is taxed as a partnership for federal and state income tax purposes.

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 recorded an impairment on our oil and natural gas properties of $34.9 million for the three months ended September 30, 2019 primarily as a result of a decline in the 12-month average price of oil and natural gas. No impairment expense was recorded for the three months ended September 30, 2018. We recorded an impairment on our oil and natural gas properties of $65.8 million and $54.8 million as a result of our quarterly full-cost ceiling analysis for the nine months ended September 30, 2019 and 2018, respectively. As of September 30, 2019, the 12-month average prices of oil and natural gas were $57.77 per Bbl of oil and $2.87 per Mcf of natural gas. These prices represent an 11.9% and 7.4% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2018, which were $65.56 per Bbl of oil and $3.10 per Mcf of natural gas.

As discussed in our Annual Report on Form 10-K for the year ended December 31, 2018, we do not intend to book proved undeveloped reserves going forward. As such, 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.

Credit Agreement

In connection with our IPO, 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, in connection with the closing of the Haymaker Acquisition, we entered into an amendment (the “Credit Agreement Amendment”) to the 2017 Credit Agreement (the 2017 Credit Agreement as amended by the Credit Agreement Amendment, the “Amended Credit Agreement”), with certain of our subsidiaries, as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto.

The Credit Agreement Amendment amended the 2017 Credit Agreement to provide for, among other things, (i) the addition of the subsidiaries we acquired in the Haymaker Acquisition, as well as the Operating Company, as guarantors under the Amended Credit Agreement, (ii) limitations on our ability to incur certain debt or issue preferred equity, (iii) limitations on redemptions of the Series A Preferred Units and our ability and our restricted subsidiaries’ ability to make distributions and other restricted payments, in each case, unless certain conditions are satisfied, (iv) increased limitations on our ability to dispose of certain assets or encumber certain assets, (v) a decrease in the applicable margin under the 2017 Credit Agreement, which varies based upon the level of borrowing base usage, by 0.25% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 2.00% to 3.00% in the case

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of LIBOR Loans (as defined in the Amended Credit Agreement) and (vi) the addition of certain restrictions on our and the Operating Company’s ability to take certain actions or amend their organizational documents.

The Credit Agreement Amendment increased commitments under the Amended Credit Agreement from $50.0 million to $200.0 million. Under the Amended Credit Agreement, availability under the secured revolving credit facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base under the Amended Credit Agreement was set at $200.0 million. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased to $500.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The borrowing base will be redetermined semiannually on May 1 and November 1 of each year based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries. In connection with the May redetermination, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million and the borrowing base was increased from $200.0 million to $300.0 million. The November borrowing base redetermination is currently being conducted and is expected to be finalized by the end of November 2019. The secured revolving credit facility matures on February 8, 2022.

As of September 30, 2019, we had approximately $91.3 million in borrowings outstanding under our senior secured credit facility. For the three months ended September 30, 2019 and 2018, we incurred $1.5 million and $1.8 million, respectively, in interest expense. For the nine months ended September 30, 2019 and 2018, we incurred $4.3 million and $2.7 million, respectively, in interest expense.

Ongoing Acquisition Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three and nine months ended September 30, 2019 and 2018 include the Phillips Acquisition, the Haymaker Acquisition and the Dropdown.

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.

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Management Services Agreements

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

Transition Services Agreement

On March 25, 2019, pursuant to the Phillips Acquisition, we entered into a Transition Services Agreement (the “Transition Services Agreement”) with Fortis Administrative Services, LLC (“Fortis”). Pursuant to the Transition Services Agreement, Fortis provided certain administrative services and accounting assistance on a transitional basis for total compensation of $300,000 from April 1, 2019 through June 1, 2019, at which point, the Transition Services Agreement was terminated.

Results of Operations

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	29,531,138	$	21,085,377	$	80,278,506	$	42,741,233
Lease bonus and other income		940,898		358,215		2,313,548		1,124,949
Gain (loss) on commodity derivative instruments, net		2,506,815		(3,035,636)		270,607		(3,858,990)
Total revenues		32,978,851		18,407,956		82,862,661		40,007,192
Costs and expenses
Production and ad valorem taxes		2,236,405		1,410,335		5,757,742		3,031,732
Depreciation and depletion expense		15,098,107		7,607,137		37,690,558		15,494,439
Impairment of oil and natural gas properties		34,880,071		—		65,828,980		54,753,444
Marketing and other deductions		2,332,010		1,689,780		5,938,093		2,868,655
General and administrative expenses		5,694,534		4,879,497		17,248,399		11,650,291
Total costs and expenses		60,241,127		15,586,749		132,463,772		87,798,561
Operating (loss) income		(27,262,276)		2,821,207		(49,601,111)		(47,791,369)
Other expense
Equity loss in affiliate		80,896		—		80,896		—
Interest expense		1,468,419		1,843,483		4,332,633		2,677,083
Net (loss) income before income taxes		(28,811,591)		977,724		(54,014,640)		(50,468,452)
Provision for income taxes		102,997		1,977,116		610,798		1,977,116
Net loss		(28,914,588)		(999,392)		(54,625,438)		(52,445,568)
Distribution and accretion on Series A preferred units		(3,469,584)		(2,840,456)		(10,408,752)		(2,840,456)
Net loss attributable to noncontrolling interests		16,146,535		141,003		33,398,555		141,003
Distribution on Class B units		(23,414)		(12,953)		(71,042)		(12,953)
Net loss attributable to common units	$	(16,261,051)	$	(3,711,798)	$	(31,706,677)	$	(55,157,974)
Production Data:
Oil (Bbls)		298,907		176,789		794,471		394,876
Natural gas (Mcf)		5,412,002		2,766,750		12,778,885		4,750,135
Natural gas liquids (Bbls)		164,202		93,339		418,106		203,839
Combined volumes (Boe) (6:1)		1,365,109		731,253		3,342,391		1,390,404

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Comparison of the Three Months Ended September 30, 2019 to the Three Months Ended September 30, 2018

Oil, Natural Gas and NGL Revenues

For the three months ended September 30, 2019, our oil, natural gas and NGL revenues were $29.5 million, an increase of $8.4 million from $21.1 million for the three months ended September 30, 2018. The increase in revenues was primarily attributable to the revenues associated with the Phillips Acquisition and the Dropdown, which contributed $4.5 million and $2.8 million, respectively, to the overall increase. Also contributing to the increase was a $3.3 million increase in revenues associated with the Haymaker Acquisition related to the significant development of properties located in the Haynesville Basin. Partially offsetting the increase in oil, natural gas and NGL revenues was a decrease in the average prices we received for oil and NGL production.

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 1,365,109 Boe or 14,838 Boe/d, for the three months ended September 30, 2019, an increase of 633,856 Boe or 6,292 Boe/d, from 731,253 Boe or 8,546 Boe/d, for the three months ended September 30, 2018.

The increase in production was primarily attributable to production associated with the Phillips Acquisition and the Dropdown, which together accounted for 272,942 Boe or 2,968 Boe/d. Also contributing to the increase was production associated with the Haymaker Acquisition, which accounted for 361,354 Boe or 3,330 Boe/d, of which 188,882 Boe or 2,053 Boe/d related to additional upside production that was previously unknown and recognized in the current quarter.

Our operators received an average of $54.87 per Bbl of oil, $2.05 per Mcf of natural gas and $12.52 per Bbl of NGL for the volumes sold during the three months ended September 30, 2019 and $64.77 per Bbl of oil, $2.56 per Mcf of natural gas and $27.45 per Bbl of NGL for the volumes sold during the three months ended September 30, 2018. The three months ended September 30, 2019 decreased 15.3% or $9.90 per Bbl of oil and 19.9% or $0.51 per Mcf of natural gas as compared to the three months ended September 30, 2018. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 19.2% or $13.35 per Bbl of oil and 18.8% or $0.55 per Mcf of natural gas for the comparable periods.

Gain on Commodity Derivative Instruments

Gain on commodity derivative instruments for the three months ended September 30, 2019 included $1.7 million of mark-to-market gains and $0.8 million of gains on the settlement of commodity derivative instruments compared to $2.8 million of mark-to-market losses and $0.2 million loss on the settlement of commodity derivative instruments for the three months ended September 30, 2018. We recorded a mark-to-market gain for the three months ended September 30, 2019 as a result of the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts.

Production and Ad Valorem Taxes

For the three months ended September 30, 2019, our production and ad valorem taxes were $2.2 million, an increase of $0.8 million compared to $1.4 million for the three months ended September 30, 2018. The increase was primarily attributable to the Haymaker Acquisition, which accounted for $0.6 million of the increase and, to the lesser extent, the Phillips Acquisition and the Dropdown, which together accounted for $0.3 million of the increase in production and ad valorem taxes.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended September 30, 2019 was $15.1 million, an increase of $7.5 million from $7.6 million for the three months ended September 30, 2018. The increase in the depreciation and depletion expense was primarily attributable to the Haymaker Acquisition, the Dropdown and the Phillips Acquisition, which together added approximately $400.8 million of depletable costs to the full-cost pool.

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developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $11.03 for the three months ended September 30, 2019, an increase of $0.66 per barrel from the $10.37 average depletion rate per barrel for the three months ended September 30, 2018. The increase in the depletion rate was due to the significant value of formerly unevaluated properties that were transferred to the depletable base in the third quarter of 2019 as a result of the drilling and completion of high interest wells in the Haynesville Basin.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

We recorded an impairment expense on our oil and natural gas properties of $34.9 million during the three months ended September 30, 2019 primarily as a result of the decline in the 12-month average price of oil and natural gas. No impairment expense was recorded for the three months ended September 30, 2018.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post‑production expense. Marketing and other deductions for the three months ended September 30, 2019 were $2.3 million, an increase of $0.6 million from $1.7 million for the three months ended September 30, 2018. The increase in marketing and other deductions was attributable to the Phillips Acquisition, which contributed $0.3 million to the increase, and to the Haymaker Acquisition and the Dropdown, which each contributed $0.2 million to the increase in marketing and other deductions.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2019 were $5.7 million, an increase of $0.8 million from $4.9 million for the three months ended September 30, 2018. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was primarily attributable a $1.1 million increase in unit-based compensation expense. Also contributing to the increase were cash general and administrative expenses resulting from the Haymaker Acquisition, the Dropdown and the Phillips Acquisition. The increase was partially offset by costs incurred during the three months ended September 30, 2018 related to our conversion to a corporation for income tax purposes and $1.4 million directly related to a transition services agreement with Haymaker Services, LLC.

Interest Expense

Interest expense for the three months ended September 30, 2019 was $1.5 million as compared to interest expense of $1.8 million for the three months ended September 30, 2018. This decrease was due to debt incurred to fund acquisitions in 2018, including the Haymaker Acquisition, which was subsequently paid down in the fourth quarter of 2018.

Provision for Income Taxes

We recorded a provision for income taxes of $0.1 million for the three months ended September 30, 2019 as a result of a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker Acquisition. Such costs are expected to continue throughout the remainder of 2019. For the three months ended September 30, 2018, we recorded a provision for income taxes of $2.0 million due to the change in our income tax status.

Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance. As of September 30, 2019, we recorded a full valuation allowance on our deferred tax assets. See Note 12—Income Taxes for further discussion.

Comparison of the Nine Months Ended September 30, 2019 to the Nine Months Ended September 30, 2018

Oil, Natural Gas and NGL Revenues

For the nine months ended September 30, 2019, our oil, natural gas and NGL revenues were $80.3 million, an increase of $37.6 million from $42.7 million for the nine months ended September 30, 2018. The increase in revenues was

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primarily attributable to the revenues associated with the Haymaker Acquisition, which represented approximately $23.5 million of the overall increase in oil, natural gas and NGL revenues, and to a lesser extent, the revenues associated with the Phillips Acquisition and the Dropdown, which contributed $15.3 million and $8.7 million, respectively, to the overall increase. Partially offsetting the increase in oil, natural gas and NGL revenues, was a decrease in the average prices we received for oil and NGL production.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 3,342,391 Boe or 12,243 Boe/d, for the nine months ended September 30, 2019, an increase of 1,951,987 Boe or 3,632 Boe/d, from 1,390,404 Boe or 8,611 Boe/d, for the nine months ended September 30, 2018. The increase in production was primarily attributable to the Haymaker Acquisition, which represented 1,309,397 Boe or 1,279 Boe/d, and to a lesser extent, production associated with the Phillips Acquisition and the Dropdown, which together accounted for 843,006 Boe or 3,088 Boe/d.

Our operators received an average of $54.65 per Bbl of oil, $2.33 per Mcf of natural gas and $16.83 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2019 and $63.35 per Bbl of oil, $2.59 per Mcf of natural gas and $26.58 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2018. The nine months ended September 30, 2019 decreased 13.7% or $8.70 per Bbl of oil and 10.0% or $0.26 per Mcf of natural gas compared to the nine months ended September 30, 2018. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 15.2% or $10.18 per Bbl of oil and 11.2% or $0.33 per Mcf of natural gas for the comparable periods.

Gain on Commodity Derivative Instruments

Gain on commodity derivative instruments for the nine months ended September 30, 2019 included $0.9 million of mark-to-market losses and $1.1 million of gains on the settlement of commodity derivative instruments compared to $3.5 million of mark-to-market losses and $0.4 million loss on the settlement of commodity derivative instruments for the nine months ended September 30, 2018. We recorded a mark-to-market gain for the nine months ended September 30, 2019 as a result of the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts. The gain for the nine months ended September 30, 2019 was partially offset by the increase in volumes hedged due to Haymaker Acquisition.

Production and Ad Valorem Taxes

For the nine months ended September 30, 2019 our production and ad valorem taxes were $5.8 million, an increase of $2.8 million compared to $3.0 million for the three months ended September 30, 2018. The increase was primarily attributable to the Haymaker Acquisition, which accounted for $1.5 million of the increase in production and ad valorem taxes and, to the lesser extent, the Phillips Acquisition and the Dropdown, which contributed $0.7 million and $0.4 million, respectively, to the increase.

Depreciation and Depletion Expense

Depreciation and depletion expense for the nine months ended September 30, 2019 was $37.7 million, an increase of $22.2 million from $15.5 million for the nine months ended September 30, 2018. The increase in the depreciation and depletion expense was primarily attributable to the Haymaker Acquisition, the Dropdown and the Phillips Acquisition, which together added approximately $400.8 million of depletable costs to the full-cost pool.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units‑of‑production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $11.26 for the nine months ended September 30, 2019, an increase of $0.19 per barrel from the $11.07 average depletion rate per barrel for the nine months ended September 30, 2018. The increase in the depletion rate was due to the significant value of formerly unevaluated properties that were transferred to the depletable base in the third quarter of 2019 as a result of the drilling and completion of high interest wells in the Haynesville Basin.

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Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

We recorded an impairment expense on our oil and natural gas properties of $65.8 million and $54.8 million during the nine months ended September 30, 2019 and 2018, respectively, as a result of our quarterly full cost ceiling analysis.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post‑production expense. Marketing and other deductions for the nine months ended September 30, 2019 were $5.9 million, an increase of $3.0 million from $2.9 million for the nine months ended September 30, 2018. The increase in marketing and other deductions was primarily attributable to the Haymaker Acquisition, which represents $1.9 million of the overall increase, and to a lesser extent, the Phillips Acquisition and the Dropdown, which contributed $1.0 million and $0.5 million, respectively, to the increase.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2019 were $17.2 million, an increase of $5.5 million from $11.7 million for the nine months ended September 30, 2018. The increase in general and administrative expenses was primarily attributable the $3.5 million increase in unit-based compensation expense. The remainder of the increase was primarily attributable to cash general and administrative expenses resulting from the Haymaker Acquisition, the Dropdown and the Phillips Acquisition.

Interest Expense

Interest expense for the nine months ended September 30, 2019 was $4.3 million as compared to interest expense of $2.7 million for the nine months ended September 30, 2018. This increase was due to debt incurred to fund acquisitions in 2018, including the Haymaker Acquisition.

Provision for Income Taxes

We recorded a provision for income taxes of $0.6 million for the nine months ended September 30, 2019 as a result of a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker Acquisition. Such costs are expected to continue throughout the remainder of 2019. For the nine months ended September 30, 2018, we recorded a provision for income taxes of $2.0 million due to the change in our income tax status.

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. On July 12, 2018, we entered into an amendment to the 2017 Credit Agreement, increasing commitments under the secured revolving credit facility from $50.0 million to $200.0 million, with an accordion feature permitting aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), to be used for general partnership purposes, including working capital and acquisitions, among other things. In connection with the redetermination of the borrowing base in May 2019, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million. As of November 1, 2019, we had an outstanding balance of $91.3 million under our secured revolving credit facility.

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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 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. We do not currently intend to 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 completed the Haymaker Acquisition by providing equity consideration for the transaction in the form of 10,000,000 common units and funding the cash consideration of the transaction through the net proceeds from the 2018 preferred offering and borrowings of $124.0 million under the Amended Credit Agreement, while the Dropdown was financed by providing equity consideration for the transaction in the form of 6,500,000 OpCo Common Units and an equal number of Class B Units, and the Phillips Acquisition was financed by providing equity consideration for the transaction in the form of 9,400,000 OpCo Common Units and an equal number of Class B Units. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well.

Because the limited liability company agreement of the Operating Company and our partnership agreement each require the Operating Company and us to distribute an amount equal to all available cash generated by each respective entity each quarter, holders of OpCo Common Units and our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and NGLs, changes to working capital or capital expenditures, (iii) tax and certain contractual obligations and (iv) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of quarterly distributions may be significant and could result in no distribution being made for any particular quarter. 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 a material amount of cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

On November 6, 2019, we paid a quarterly cash distribution on the Series A Preferred Units of $1.9 million for the quarter ended September 30, 2019.

On November 8, 2019, the Operating Company paid a quarterly cash distribution of $0.428494 to holders of OpCo Common Units. As to the Partnership, $0.008494 of the distribution corresponds to a tax payment made by us from cash reserves in the third quarter of 2019. The third quarter 2019 tax payment made by us was generated by a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker Acquisition. Under the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us.

On November 8, 2019, we paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of approximately $23,388 for the quarter ended September 30, 2019.

On October 25, 2019 the Board of Directors declared a quarterly cash distribution of $0.42 per common unit for the quarter ended September 30, 2019. The distribution will be paid on November 11, 2019 to common unitholders and OpCo common unitholders of record as of the close of business on November 4, 2019.

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Cash Flows

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


	Nine Months Ended September 30,
	2019		2018
Cash Flow Data:
Net cash provided by operating activities	$	63,979,961	$	18,592,070
Net cash used in investing activities		(5,974,089)		(200,394,775)
Net cash (used in) provided by financing activities		(53,481,877)		192,705,177
Net increase in cash	$	4,523,995	$	10,902,472

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 the change in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the nine months ended September 30, 2019 were $64.0 million, an increase of $45.4 million compared to $18.6 million for the nine months ended September 30, 2018. The increase in cash flows provided by operating activities was primarily attributable to the Haymaker Acquisition and Dropdown in the third and fourth quarters of 2018, respectively, and to the Phillips Acquisition in the first quarter of 2019.

Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2019 decreased by $194.4 million compared to the nine months ended September 30, 2018. For the nine months ended September 30, 2019, we used $3.0 million to fund capital commitments of a joint venture with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, $1.2 million to fund the Phillips Acquisition, $1.0 million to fund the deposit in connection with the acquisition of various mineral and royalty interests in Oklahoma and $0.8 million to fund the remodel of office space. For the nine months ended September 30, 2018, we used $210.6 million to fund the Haymaker Acquisition and $0.4 million to fund the remodel of office space, partially offset by $10.6 million in proceeds received from the sale of oil and natural gas properties.

Financing Activities

Cash flows used in financing activities were $53.5 million for the nine months ended September 30, 2019 compared to $192.7 million of cash flows provided by financing activities for the nine months ended September 30, 2018. Cash flows used in financing activities for the nine months ended September 30, 2019 consist of $57.0 million of distributions paid to holders of common units and OpCo common units, Series A Preferred Units and Class B Units and $0.7 million of issuance costs paid on Series A Preferred Units, partially offset by $4.0 million of additional borrowings under our secured revolving credit facility and $0.5 million in contributions from our Class B unitholders. Cash flows provided by financing activities for the nine months ended September 30, 2018 consist of $124.4 million of additional borrowings under our secured revolving credit facility, $103.4 million in proceeds from the issuance of Series A Preferred Units and $0.6 million in contributions from our Class B unitholders, partially offset by $25.4 million of distributions paid to unitholders of common units and Series A Preferred Units, $6.9 million of repayments on our secured revolving credit facility and $3.4 million paid in loan origination costs.

Capital Expenditures

During the nine months ended September 30, 2019, we paid approximately $1.2 million in connection with the Phillips Acquisition and a $1.0 million deposit in connection with the acquisition of various mineral and royalty interests in Oklahoma. During the nine months ended September 30, 2018, we paid approximately $210.6 million in connection with the Haymaker Acquisition.

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Indebtedness

In connection with our IPO, on January 11, 2017, we entered into the 2017 Credit Agreement with Frost Bank. In connection with the closing of the Haymaker Acquisition, we entered into the Credit Agreement Amendment. Under the Amended Credit Agreement, availability under our secured revolving credit facility will continue to equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The secured revolving credit facility will mature on February 8, 2022.

Pursuant to the Credit Agreement Amendment, aggregate commitments under the Amended Credit Agreement were increased to $200.0 million providing for maximum availability of $200.0 million. The borrowing base will be redetermined semi-annually November 1 and May 1 of each year based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries. In connection with the May redetermination, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million and the borrowing base was increased from $200.0 million to $300.0 million. The November borrowing base redetermination is currently being conducted and is expected to be finalized by the end of November 2019. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.

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, 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 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The 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 September 30, 2019, we had outstanding borrowings of $91.3 million under the secured revolving credit facility and $208.7 million of available capacity.

For additional information on our Amended Credit Agreement, please read Note 7―Long-Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report.

New and Revised Financial Accounting Standards

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

Critical Accounting Policies and Related Estimates

There have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.

Contractual Obligations and Off‑Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018. As of September 30, 2019, we did not have any off‑balance sheet arrangements other than operating leases.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices that our operators receive

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for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparty to the contracts is an unrelated third party.

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

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

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

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of September 30, 2019, we had one counterparty, which is also one of the lenders under our credit facility.

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

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of September 30, 2019, we had total borrowings outstanding under our secured revolving credit facility of $91.3 million. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense of approximately $0.9 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a‑15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a‑15(e) and 15d‑15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2019.

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Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a description of the Partnership’s legal proceedings, see Note 15—Commitments and Contingencies to the condensed consolidated financial statements, which is incorporated by reference herein.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the risks under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018. There have been no material changes to the risk factors previously discussed in Item 1A. Risk Factors in the Partnership’s 2018 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.

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

On July 29, 2019, we issued 400,000 common units to Haymaker Minerals & Royalties, LLC in exchange for 400,000 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 any future holders of OpCo Common Units and Class B Units from time to time party thereto.

On September 19, 2019, we issued 26,084 common units to Haymaker Management, LLC in exchange for 26,084 OpCo Common Units and an equal number of Class B Units pursuant to the terms of the Exchange Agreement.

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

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Item 6. Exhibits

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017)
3.2	—	Third Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017)
3.4	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s 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*	—	XBRL Instance Document.
101.SCH*	—	XBRL Taxonomy Extension Schema Document
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document

* —filed herewith

** —furnished herewith

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SIGNATURES

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


	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner

Date: November 8, 2019	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: November 8, 2019	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer