UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM ~~10‑Q~~10-Q


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

For the quarterly period ended ~~September~~June 30, ~~2017~~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 ~~and posted on its corporate website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S‑T during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes ☒ No ☐

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


Large accelerated filer	☐		Accelerated filer	☒
Non-accelerated filer	☐	Non‑accelerated filer ☒ (Do not check if a smaller reporting company)	Smaller reporting company ☐	☒
Emerging growth company	☒

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

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

As of ~~November 8, 2017, 16,509,799~~August 2, 2019, the registrant had outstanding 23,494,135 common units ~~of the registrant were outstanding.~~representing limited partner interests and 23,414,342 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 ~~Partners’ Capital and Predecessor Members’~~Unitholders’ Equity	3
Condensed Consolidated Statements of Cash Flows	4
Notes to Condensed Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	1618
Item 3. Quantitative and Qualitative Disclosures About Market Risk	3134
Item 4. Controls and Procedures	3135


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	3236
Item 1A. Risk Factors	3236
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 6. Exhibits	3237
Signatures	3438

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	Partnership		Predecessor
	September 30,		December 31,		June 30,		December 31,
	2017		2016		2019		2018
ASSETS
Current assets
Cash and cash equivalents	$	6,226,479	$	505,880	$	16,887,771	$	15,773,987
Oil, natural gas and NGL receivables		5,501,513		474,103		18,871,778		18,809,170
Other current assets		258,785		344,368
Commodity derivative assets						1,957,249		2,981,117
Accounts receivable and other current assets						376,121		50,551
Total current assets		11,986,777		1,324,351		38,092,919		37,614,825
Property and equipment, net		204,343		261,568		816,614		429,602
Oil and natural gas properties
Oil and natural gas properties, using full-cost method of accounting		285,043,287		70,888,121
Less: accumulated depreciation, depletion, accretion and impairment		(11,047,641)		(51,948,355)
Total oil and natural gas properties		273,995,646		18,939,766
Deposits on oil and natural gas properties		3,949,000		—
Oil and natural gas properties, using full cost method of accounting ($351,068,528 and $280,304,353 excluded from depletion at June 30, 2019 and December 31, 2018, respectively)						987,748,241		818,594,943
Less: accumulated depreciation, depletion and impairment						(161,301,065)		(107,779,453)
Total oil and natural gas properties, net						826,447,176		710,815,490
Right-of-use assets, net						619,944		—
Commodity derivative assets						—		1,246,829
Loan origination costs, net		270,833		13,046		2,749,255		3,178,627
Total assets	$	290,406,599	$	20,538,731	$	868,725,908	$	753,285,373

LIABILITIES AND PARTNERS' CAPITAL (PREDECESSOR MEMBERS' EQUITY)
LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	152,569	$	1,030,862	$	1,184,477	$	1,331,081
Other current liabilities		2,146,834		112,508		4,205,607		2,468,945
Asset retirement obligations		—		27,013
Total current liabilities		2,299,403		1,170,383		5,390,084		3,800,026
Asset retirement obligations		—		14,468
Other liabilities		—		123,158
Operating lease liabilities						615,516		—
Commodity derivative liabilities						291,362		—
Long-term debt		22,214,090		10,598,860		87,309,544		87,309,544
Total liabilities		24,513,493		11,906,869		93,606,506		91,109,570
Commitments and contingencies
Predecessor members' equity		—		8,631,862
Partners' capital		265,893,106		—
Total liabilities and partners' capital (predecessor members' equity)	$	290,406,599	$	20,538,731
Commitments and contingencies (Note 15)
Mezzanine equity:
Series A preferred units (110,000 units issued and outstanding as of June 30, 2019 and December 31, 2018)						71,820,563		69,449,006
Unitholders' equity:
Common units (23,094,135 units issued and outstanding as of June 30, 2019 and 18,056,487 units issued and outstanding as of December 31, 2018)						337,096,345		293,992,935
Class B units (23,814,342 units issued and outstanding as of June 30, 2019 and 19,453,258 units issued and outstanding as of December 31, 2018)						1,190,717		972,663
Total unitholders' equity						338,287,062		294,965,598
Noncontrolling interest						365,011,777		297,761,199
Total equity						703,298,839		592,726,797
Total liabilities, mezzanine equity and unitholders' equity					$	868,725,908	$	753,285,373

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Partnership		Predecessor		Partnership		Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,		Nine Months Ended September 30,		Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2017		2016		2019		2018		2019		2018
Revenue
Oil, natural gas and NGL revenues	$	8,351,399	$	969,084	$	20,656,741	$	318,310	$	2,572,477	$	27,913,975	$	10,847,677	$	50,747,368	$	21,655,856
Lease bonus and other income												1,289,044		398,610		1,372,650		766,734
Gain (loss) on commodity derivative instruments												2,733,582		(538,389)		(2,236,208)		(823,354)
Total revenues												31,936,601		10,707,898		49,883,810		21,599,236
Costs and expenses
Production and ad valorem taxes		778,733		120,315		1,602,520		19,651		203,567		1,924,943		805,396		3,521,337		1,621,397
Depreciation, depletion and accretion expense		4,488,915		418,969		11,156,292		113,639		1,244,023
Depreciation and depletion expense												12,311,443		3,431,594		22,592,451		7,887,302
Impairment of oil and natural gas properties		—		306,959		—		—		4,992,897		28,146,711		—		30,948,909		54,753,444
Marketing and other deductions		424,702		320,698		1,068,509		110,534		570,521		1,749,040		609,033		3,606,083		1,178,875
General and administrative expense		2,314,718		463,501		5,707,093		532,035		1,252,001		6,220,499		4,000,022		11,553,865		6,770,794
Total costs and expenses		8,007,068		1,630,442		19,534,414		775,859		8,263,009		50,352,636		8,846,045		72,222,645		72,211,812
Operating income (loss)		344,331		(661,358)		1,122,327		(457,549)		(5,690,532)
Operating (loss) income												(18,416,035)		1,861,853		(22,338,835)		(50,612,576)
Other expense
Interest expense		225,302		103,596		468,429		39,307		314,081		1,441,651		483,558		2,864,214		833,600
Income (loss) before income taxes		119,029		(764,954)		653,898		(496,856)		(6,004,613)
State income taxes		—		4,212		—		—		13,401
Net income (loss)	$	119,029	$	(769,166)	$	653,898	$	(496,856)	$	(6,018,014)
Net (loss) income before income taxes												(19,857,686)		1,378,295		(25,203,049)		(51,446,176)
Provision for income taxes												507,801		—		507,801		—
Net (loss) income												(20,365,487)		1,378,295		(25,710,850)		(51,446,176)
Distribution and accretion on Series A preferred units												(3,469,584)		—		(6,939,168)		—
Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests												12,100,511		—		17,252,020		—
Distribution on Class B units												(23,814)		—		(47,628)		—
Net (loss) income attributable to common units											$	(11,758,374)	$	1,378,295	$	(15,445,626)	$	(51,446,176)

Net income (loss) attributable to common units
Net (loss) income attributable to common units
Basic	$	0.01	$	(1.27)	$	0.04	$	(0.82)	$	(9.96)	$	(0.54)	$	0.08	$	(0.78)	$	(3.14)
Diluted	$	0.01	$	(1.27)	$	0.04	$	(0.82)	$	(9.96)	$	(0.54)	$	0.08	$	(0.78)	$	(3.14)
Weighted average number of common units outstanding
Basic		16,337,985		604,137		16,334,774		604,137		604,137		21,727,185		16,377,476		19,859,618		16,361,619
Diluted		16,503,664		604,137		16,434,385		604,137		604,137		21,727,185		16,809,149		19,859,618		16,361,619

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN ~~PARTNERS’ CAPITAL AND PREDECESSOR MEMBERS’~~UNITHOLDERS’ EQUITY

(Unaudited)

Units

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

604,137

$
8,631,862

Unit-based compensation

—

50,422

Net loss

—

(496,856)

Transfer of membership units to Rivercrest Royalties Holdings, LLC

(604,137)

(98,988)

Partners' capital - February 8, 2017 (Partnership)

—

8,086,440

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

1,191,974

—

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

9,390,734

169,033,212

Common units sold to public

5,750,000

103,500,000

Underwriting discount and structuring fee incurred at initial public offering

—

(7,245,000)

Distributions to unitholders

—

(8,705,333)

Unit-based compensation

177,091

569,889

Net income

—

653,898

Partners' capital - September 30, 2017

16,509,799

$
265,893,106


	Six Months Ended June 30, 2019
									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Balance at January 1, 2019		18,056,487	$	293,992,935		19,453,258	$	972,663	$	297,761,199	$	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		—		(15,003,898)		—		—		—		(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		300,579,597		27,414,342		1,370,717		440,652,288		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		—		(17,356,606)		—		—		—		(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	$	337,096,345		23,814,342	$	1,190,717	$	365,011,777	$	703,298,839


	Six Months Ended June 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

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Partnership		Predecessor
	Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,		Nine Months Ended September 30,		Six Months Ended June 30,
	2017		2017		2016		2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	653,898	$	(496,856)	$	(6,018,014)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and accretion expense		11,156,292		113,639		1,244,023
Net loss							$	(25,710,850)	$	(51,446,176)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and depletion expense								22,592,451		7,887,302
Impairment of oil and natural gas properties		—		—		4,992,897		30,948,909		54,753,444
Amortization of right-of-use assets								22,578		—
Amortization of loan origination costs		41,667		4,241		34,245		518,149		31,250
Amortization of tenant improvement allowance		—		(2,864)		(25,777)
Unit-based compensation		569,889		50,422		453,795		3,883,174		1,391,973
Loss on commodity derivative instruments, net of settlements								2,562,059		681,530
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(496,886)		14,551		11,258		3,893,763		195,074
Other current assets		(258,785)		333,056		1,246,269
Accounts receivable and other current assets								(325,570)		10,032
Accounts payable		152,569		247,972		(1,071,453)		(949,806)		1,204,349
Other current liabilities		2,146,834		(77,442)		89,550		1,736,663		(519,935)
Operating lease liabilities								(27,006)		—
Net cash provided by operating activities		13,965,478		186,719		956,793		39,144,514		14,188,843
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(57,592)		—		(18,016)		(406,761)		(31,304)
Proceeds from sale of oil and natural gas properties								—		10,576,595
Deposits on oil and natural gas properties		(3,949,000)		—		—		—		(21,005,000)
Purchase of oil and natural gas properties		(113,183,664)		(523)		(75,883)		(998,550)		(17,585)
Net cash used in investing activities		(117,190,256)		(523)		(93,899)		(1,405,311)		(10,477,294)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from initial public offering		96,255,000		—		—
Contributions from Class B unitholders								470,000		—
Redemption of Class B contributions on converted units								(9,862)		—
Issuance costs paid on Series A preferred units								(717,612)		—
Distributions to unitholders		(8,705,333)		—		—		(32,360,504)		(13,131,816)
Distributions on Series A preferred units								(3,850,000)		—
Distributions to Class B unitholders								(47,628)		—
Borrowings on long-term debt		22,214,090		—		—		—		19,000,000
Repayments on long-term debt		—		—		(550,000)		—		(6,870,596)
Payment of loan origination costs		(312,500)		—		(13,000)		(88,777)		—
Net cash provided by (used in) financing activities		109,451,257		—		(563,000)
Restricted units used for tax withholding								(21,036)		—
Net cash used in financing activities								(36,625,419)		(1,002,412)
NET INCREASE IN CASH AND CASH EQUIVALENTS		6,226,479		186,196		299,894		1,113,784		2,709,137
CASH AND CASH EQUIVALENTS, beginning of period		—		505,880		379,741		15,773,987		5,625,495
CASH AND CASH EQUIVALENTS, end of period	$	6,226,479	$	692,076	$	679,635	$	16,887,771	$	8,334,632
Supplemental cash flow information:
Cash paid for interest	$	276,246	$	34,505	$	280,010	$	2,685,994	$	977,487
Cash paid for taxes	$	—	$	5,355	$	17,468
Non-cash investing and financing activities:
Capital expenditures through issuance of common units	$	176,404,698	$	—	$	—
Right-of-use assets obtained in exchange for operating lease liabilities							$	642,522	$	—
Capital expenditures and consideration payable included in accounts payable and other liabilities							$	35,382	$	3,718,237
Oil and natural gas property acquisition costs in accounts payable							$	104,031	$	—
Units issued in exchange for oil and natural gas properties							$	171,550,000	$	—
Non-cash deemed distribution to Series A preferred units							$	3,089,168	$	—
Redemption of Class B contributions on converted units in accounts payable							$	242,084	$	—

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “the Partnership,” ~~“we,” “our,” “us”~~ 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 ~~“the Predecessor,” or “Rivercrest” refer to Rivercrest Royalties, LLC, the predecessor for accounting and financial reporting purposes. References to~~ “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner.

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

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

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

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

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements ~~of the Partnership~~ have been prepared in accordance with accounting principles generally accepted ~~accounting principles~~ in the United States (“GAAP”) for interim financial information and with the instructions to Form 10‑Q and pursuant to the rules and regulations of the U.S. Securities and Exchange ~~Commission (“SEC”).~~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 ~~and the Predecessor’s financial statements for the years ended December 31, 2016 and 2015, which are included in the Partnership’s~~ Annual Report on Form 10-K for the year ended December 31, ~~2016.~~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 ~~of a normal recurring nature~~ necessary to fairly present the financial position and results of operations for the interim periods in accordance with ~~GAAP.~~GAAP and all adjustments are of a normal recurring nature. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.

~~Table~~Preparation of ~~Contents~~

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

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.

Table of Contents

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, ~~Estimates~~

~~The preparation~~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 ~~unaudited~~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 August 2, 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 ~~conformity with GAAP requires management to make estimates and assumptions that affect~~ the ~~reported amounts of assets, liabilities, revenues and expenses,~~Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, as well as ~~certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and~~the items noted below. There have been no substantial changes in such policies or the application of such policies during the six months ended June 30, 2019, other ~~factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used~~than those discussed below in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities and the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties.

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

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

Reclassification of Prior Period Presentation

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

~~Cash and Cash Equivalents~~

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

~~Accounts Receivable~~

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

~~Property and Equipment~~

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

~~Table of Contents~~

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

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

~~Oil and Natural Gas Properties~~

The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.

The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. The Partnership has not assigned any value to unproved properties in which it holds an interest. The full-cost ceiling is evaluated at the end of each period and additionally when events indicate possible impairment.

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

The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. The fair value of these acquired assets was based on the common units issued to the Contributing Parties, other than the Predecessor, multiplied by the IPO price per common unit plus the net proceeds of the IPO that were distributed to the Contributing Parties, excluding the value of any common units or net proceeds distributed to the Predecessor. In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined the fair value of the acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that we are required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of September 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, the Partnership considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO, and management affirmed that there has not been a material change to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at September 30, 2017 of $240.8 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $78.4 million for the period ending September 30, 2017. The Partnership will continue to assess the fair value of the acquired assets at each periodic reporting date to ensure inclusion in the ceiling calculation is not required through the December 31, 2017 reporting period, which is the period of the exemption extended by the SEC. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired. All of the Partnership’s oil and natural gas properties are subject to the full-cost ceiling test. No impairment expense was recorded for the period from February 8, 2017 to September 30, 2017.

No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). The Predecessor recorded a full-cost ceiling impairment of $0.3 million and $5.0 million

~~Table of Contents~~

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

~~for the three and nine months ended September 30, 2016, respectively, as a result of reductions in estimated proved reserves and commodity prices.~~

The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change.

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

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

~~Other Current Liabilities~~

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

~~Asset Retirement Obligations~~

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

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

~~Other Long-Term Liabilities~~

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

~~Income Taxes~~

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

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

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

~~Table of Contents~~

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

The Partnership and the Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to September 30, 2017, the Predecessor 2017 Period, and the nine months ended September 30, 2016, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions.

The Partnership has filed all tax returns to date that are currently due. Tax years after December 31, 2013 remain subject to possible examination by taxing authorities although no such examination has been requested.

~~Concentration of Credit Risk~~

The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGL produced and sold from its properties. It is believed that the loss of any single purchaser would not have a material adverse effect on ~~the results of operations.~~previously reported net income (loss), total cash flows from operations or working capital.

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

~~Revenue Recognition~~

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

As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and NGL sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGL produced and sold from the properties.

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

~~Fair Value Measurements~~

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 and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the accompanying unaudited consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future.

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

~~Table of Contents~~

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

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

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

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

~~Level 3—unobservable inputs for the asset or liability.~~

The Predecessor’s ARO is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 8 for the summary of changes in the fair value of the Predecessor’s ARO for the Predecessor 2017 Period.

~~Recently Issued~~New Accounting Pronouncements

Recently Adopted Pronouncements

In ~~January 2017,~~February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, “Business Combinations—Clarifying the Definition of a Business.” This update apples to all entities that must determine whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The update requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the transaction should not be accounted for as a business. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years. This update should be and will be applied prospectively on or after the effective date. The adoption of this update will change the process that the Partnership uses to evaluate whether it has acquired a business or an asset. This update is not expected to have a material impact on the Partnership’s financial statements or results of operations.

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

In June 2016, the FASB issued ASU 2016‑13, “Measurement of Credit Losses on Financial Instruments.” ASU 2016‑13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Partnership does not believe this standard will have a material impact on its financial statements.

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

~~Table of Contents~~

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

In March 2016, the FASB issued ASU 2016‑09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016‑09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Partnership adopted this standard effective at the issuance of its restricted units under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) on May 12, 2017. The Partnership elected to account for forfeitures as they occur as a result of adopting this standard.

In March 2016, the FASB issued ASU 2016-08, “Revenue from Contracts with Customers—Principal versus Agent Considerations (Reporting Revenue Gross versus Net).” Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, and early application is not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Partnership is still evaluating the impact of this standard, however, it does not expect that there will be a significant change in the manner of the Partnership’s revenue recognition. The Partnership expects that certain additional disclosures will be required upon adoption of this standard. The Partnership is still determining which adoption method it will use.

~~In February 2016, the FASB issued ASU~~ 2016‑02, “Leases.” ASU 2016‑02 requires the recognition of ~~lease~~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. This~~year, with early adoption permitted. The Partnership adopted this update ~~should be applied~~ using athe modified retrospective approach, ~~and early adoption is permitted.~~effective January 1, 2019. The ~~Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases.~~

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

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

~~NOTE 3—ACQUISITIONS~~

In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million gross acres (6,881 net royalty acres) for an aggregate purchase price of approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility.six months ended June 30, 2019.

116

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

~~NOTE 4—LONG-TERM DEBT~~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 June 30, 2019. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of June 30, 2019 was 9.09 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 six months ended June 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 six months ended June 30, 2019. The total operating lease expense recorded for the three and six months ended June 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 asset. The underlying assets were capitalized in July 2019 upon commencement of the lease.

Future minimum lease commitments at June 30, 2019 were as follows:


			Remainder of
	Total		2019		2020		2021		2022		2023		Thereafter
Operating leases	$	835,775	$	45,822	$	90,078	$	90,078	$	90,487	$	87,463	$	431,847
Less: Imputed Interest		(220,259)
Total	$	615,516

In ~~connection with~~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 six months ended June 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 six months ended June 30, 2019.

In July 2018, the FASB issued ASU 2018-11, “Lease (Topic 842): Targeted Improvements.” This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 six months ended June 30, 2019.

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 ~~IPO,~~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 $18.25 on March 25, 2019. The assets acquired in the Phillips Acquisition consist of approximately 866,528 gross acres and 12,210 net royalty acres.

The following unaudited pro forma results of operations reflect the Partnership’s results as if the acquisition of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Total revenues	$	31,936,601	$	31,306,192	$	54,892,396	$	61,437,506
Net (loss) income attributable to common units	$	(11,758,374)	$	5,319,058	$	(10,972,888)	$	(15,566,172)

Net (loss) income attributable to common units
Basic	$	(0.51)	$	0.23	$	(0.48)	$	(0.67)
Diluted	$	(0.51)	$	0.23	$	(0.48)	$	(0.67)

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Joint Ventures

On June 19, 2019, the Partnership entered into a ~~$50.0 million secured revolving credit facility that~~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 ~~secured~~49.3% and its total capital commitment will not exceed $15.0 million. The Joint Venture will be managed by ~~substantially all~~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. As of June 30, 2019, no investments had been made by the Joint Venture and the Partnership had not funded any amounts under its capital commitment.

Divestitures

In May 2018, the Partnership executed two purchase and sale agreements to sell a small portion of its ~~assets and~~Delaware Basin acreage for $10.6 million, which was recorded as a reduction in the ~~assets of its wholly owned subsidiaries. Availability under~~full-cost pool, with no gain or loss recorded on the ~~secured revolving credit facility equals~~sale. At the ~~lesser~~time of the ~~aggregate maximum commitments~~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 ~~lenders~~market price for oil and natural gas. To mitigate the ~~borrowing base.~~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 ~~borrowing base will be re-determined semi-annually on February 1~~Partnership enters into oil and ~~August 1~~natural gas derivative contracts that contain netting arrangements with each counterparty.

As of ~~each year~~June 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 20% 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.

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 presented on a net basis in the accompanying unaudited condensed consolidated statements of operations and consisted of the following:


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Beginning fair value of commodity derivative instruments	$	(937,938)		(531,287)	$	4,227,946	$	(318,829)
Gain (loss) on commodity derivative instruments		2,733,582		(538,389)		(2,236,208)		(823,354)
Net cash (received) paid on settlements of derivative instruments		(129,757)		69,317		(325,851)		141,824
Ending fair value of commodity derivative instruments	$	1,665,887	$	(1,000,359)	$	1,665,887	$	(1,000,359)

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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


		June 30,		December 31,
Classification	Balance Sheet Location	2019		2018
Assets:
Current asset	Commodity derivative assets	$	1,957,249	$	2,981,117
Long-term asset	Commodity derivative assets		—		1,246,829
Liabilities:
Current liability	Commodity derivative liabilities		—		—
Long-term liability	Commodity derivative liabilities		(291,362)		—
		$	1,665,887	$	4,227,946

As of June 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
June 2019 - December 2019	131,396	$	61.47	$	53.07	$	63.47
January 2020 - December 2020	224,356	$	55.48	$	50.45	$	61.43
January 2021 - June 2021	110,993	$	55.25	$	54.52	$	56.10

Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
July 2019 - December 2019	1,945,432	$	2.74	$	2.74	$	2.76
January 2020 - December 2020	3,582,862	$	2.64	$	2.51	$	2.94
January 2021 - June 2021	1,562,411	$	2.62	$	2.43	$	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 June 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.

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

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

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 consists of the following:


	June 30,		December 31,
	2019		2018
Oil and natural gas properties
Proved properties	$	636,679,713	$	538,290,590
Unevaluated properties		351,068,528		280,304,353
Less: accumulated depreciation, depletion and impairment		(161,301,065)		(107,779,453)
Total oil and natural gas properties	$	826,447,176	$	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 $28.1 million for the three months ended June 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 June 30, 2018. The Partnership recorded an impairment on its ~~wholly owned subsidiaries.~~ oil and natural gas properties of $30.9 million and $54.8 million during the six months ended June 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.

NOTE 7—LONG-TERM DEBT

In connection with its initial public offering (“IPO”), on January 11, 2017, the ~~August 1 redetermination~~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 ~~secured revolving credit facility,~~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 ~~was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing~~usage, by 0.25% for ~~maximum availability under~~each applicable

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

level as set forth in the ~~revolving credit facility~~Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ~~$50.0 million. The secured revolving credit facility permits aggregate commitments~~ABR Loans (as defined in the Amended Credit Agreement) and 2.00% to ~~be increased to $100.0 million, subject to~~3.00% in the ~~satisfaction~~case of LIBOR Loans (as defined in the Amended Credit Agreement) and (vi) the addition of certain ~~conditions~~restrictions on the Partnership’s and the ~~procurement of additional commitments from new~~Operating Company’s ability to take certain actions or ~~existing lenders. The secured revolving credit facility matures on February 8, 2022.~~amend their organizational documents.

The ~~secured revolving credit facility~~Amended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The ~~secured revolving credit facility~~Amended Credit Agreement also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 4.0 to ~~1.0;~~1.0 and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The ~~secured revolving credit facility~~Amended Credit Agreement also contains customary events of default, including non‑payment, 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 order to include all assets acquired through the Phillips Acquisition in the borrowing base available under the Amended Credit Agreement, a borrowing base redetermination was completed in late May 2019. In connection with the 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 secured revolving credit facility matures on February 8, 2022.

During the three and six months ended June 30, 2019, the Partnership did not incur or repay any borrowings under the secured revolving credit facility. As of ~~September~~June 30, ~~2017,~~2019, the Partnership’s outstanding balance was ~~$22.2~~$87.3 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of ~~September~~June 30, ~~2017.~~2019.

~~During the period ended September~~As of June 30, ~~2017,~~2019, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% ~~and~~or Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the ~~period from February 8, 2017 to September~~six months ended June 30, ~~2017,~~2019, the weighted average interest rate on the Partnership’s outstanding borrowings was ~~3.51%~~4.74%.

On January 31, 2014, the Predecessor entered into a credit agreement with Frost Bank for up to a $50.0 million revolving credit facility. The credit facility was subject to borrowing base restrictions and was collateralized by certain properties. The borrowing base on the Predecessor’s credit facility was $20.0 million with interest payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans, with all principal and unpaid interest due at maturity on January 15, 2018. As of December 31, 2016, the Predecessor had outstanding advances on long-term debt totaling $10.6 million. On February 8, 2017, the Predecessor repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the sale of the Predecessor’s mineral and royalty interests to the Partnership.

NOTE ~~5—COMMON~~8—PREFERRED UNITS

On February 8, 2017, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the initial assets were contributed to the Partnership by the Contributing Parties at the time of the IPO. On May 12, 2017, the Partnership issued 163,324 restricted units under the LTIP.

On May 2, 2017, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date ofIn July 2018, in connection with the closing of the ~~Partnership’s IPO through March 31, 2017.~~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. 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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 June 30, 2019		110,000

NOTE 9—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has limited partner units. As of June 30, 2019, the Partnership had a total of 23,094,135 common units issued and outstanding and 23,814,342 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		5,038,916
Restricted units used for tax withholding		(1,268)
Balance at June 30, 2019		23,094,135

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

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

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		(5,038,916)
Balance at June 30, 2019		23,814,342

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.

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

~~On July 28, 2017, the Board~~The Class B Units and OpCo Common Units are exchangeable together into an equal number of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The distribution was paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017.

On August 9, 2017, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of (i) common units in an amount equal to $30,000 to certain non-employee directors of the Partnership under the LTIP, which were fully vested as of the grant date, and (ii) a total of 4,247 restricted units to certain consultants under the LTIP. Such grants were made on August 11, 2017.

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

NOTE 6—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 ~~common~~restricted units granted under the ~~Partnership’s LTIP~~Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) for its employees, directors and consultants and unvested options granted under the Predecessor’s long-term incentive plan as described in Note 7—Unit-Based Compensation. For the Predecessor 2017 Period and the nine months ended September 30, 2016, the effectpotential conversion of the 110,000 options issued under the Predecessor’s long-term incentive plan were anti-dilutive. Therefore, the options issued under the Predecessor’s long-term incentive plan were not included in the diluted EPU calculation on the consolidated statements of operations for those periods.Class B Units.

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


	Partnership		Predecessor		Partnership		Predecessor				Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended September 30,		Three Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,		Nine Months Ended September 30,		2019		2018		2019		2018
Net (loss) income attributable to common units											$	(11,758,374)	$	1,378,295	$	(15,445,626)	$	(51,446,176)
	2017		2016		2017		2017		2016
Net income (loss)	$	119,029	$	(769,166)	$	653,898	$	(496,856)	$	(6,018,014)
Weighted average number of common units outstanding:
Basic												21,727,185		16,377,476		19,859,618		16,361,619
Effect of dilutive securities:
Series A preferred units												—		—		—		—
Class B units												—		—		—		—
Restricted units												—		431,673		—		—
Diluted												21,727,185		16,809,149		19,859,618		16,361,619

Net income (loss) attributable to common units
Net (loss) income attributable to common units
Basic	$	0.01	$	(1.27)	$	0.04	$	(0.82)	$	(9.96)	$	(0.54)	$	0.08	$	(0.78)	$	(3.14)
Diluted	$	0.01	$	(1.27)	$	0.04	$	(0.82)	$	(9.96)	$	(0.54)	$	0.08	$	(0.78)	$	(3.14)
Weighted average number of common units outstanding
Basic		16,337,985		604,137		16,334,774		604,137		604,137
Diluted		16,503,664		604,137		16,434,385		604,137		604,137

The calculation of diluted net loss per unit for the three and six months ended June 30, 2019 excludes the conversion of Series A Preferred Units to common units, the conversion of the Class B Units to common units and 976,684 of unvested restricted units because their inclusion in the calculation would be anti-dilutive. The calculation of diluted net loss per unit for the six months ended June 30, 2018 excludes 438,785 unvested restricted units because their inclusion in the calculation would be anti-dilutive.

NOTE 7—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 ~~of up to 2,041,600 common units in the aggregate~~ to its employees, directors and consultants. The restricted units issued under ~~our~~the Partnership’s LTIP generally vest in one-third 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 ~~will be accrued for services provided during~~is treated in the ~~intervening periods between~~same manner as that of the ~~grant~~employees and ~~vesting dates, utilizing then-current fair values for the awards and applying mark-to-market accounting until actual vesting occurs.~~directors.

1314

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

Weighted

Weighted

Weighted

Average

Average

Average

Grant-Date

Market-Date

Remaining

Fair Value

Fair Value

Contractual

Units

per Unit

per Unit

Term
Unvested at February 8, 2017

—

$
—

$
—

—
Granted - service condition employees

143,318

18.655

—

—
Granted - service condition consultants

24,253

—

15.780

—
Granted - non-employee directors

9,520

15.780

Vested

(9,520)

—

—

—
Forfeited

—

—

—

—
Exercised

—

—

—

—
Unvested at September 30, 2017

167,571

$
18.655

$
15.780

1.616 years


		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2018	1,157,924	$	18.054	2.696 years
Vested	(181,240)		18.752	—
Unvested at June 30, 2019	976,684	$	17.924	1.744 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 IPO, the Predecessor had a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options as compensation for services performed for the Predecessor. The options carried a distribution right, whereby the option holder received distributions that were commensurate with those given to holders of membership units.

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

Weighted

Weighted

Average

Average

Remaining

Exercise

Contractual

Units

Price

Term
Outstanding, December 31, 2016 - Predecessor

110,000

$
100

8.00 years
Granted

—

—

—
Forfeited

—

—

—
Exercised

—

—

—
Outstanding, February 7, 2017

110,000

$
100

7.92 years
Exercisable, February 7, 2017

—

$
—

—

For the Predecessor 2017 Period and the nine months ended September 30, 2016, total compensation expense for awards under the Predecessor’s long-term incentive plan was $50,422 and $453,795, respectively, and is included general and administrative expenses in the accompanying unaudited consolidated statements of operations. In connection with the transactions that were completed at the closingeffective date of the Partnership’s ~~IPO,~~change in income tax status, the ~~outstanding options to purchase membership units under~~Partnership was organized as a pass-through entity for income tax purposes. As a result, the ~~Predecessor’s long-term incentive plan expired~~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 $0.5 million for the three and ~~were not converted to units in~~six months ended June 30, 2019. The tax payment made by the ~~Partnership.~~

~~NOTE 8—ASSET RETIREMENT OBLIGATIONS~~

~~Prior~~Partnership for the three and six months ended June 30, 2019 was generated by a gross income allocation related to the ~~transactions that~~Series A Preferred Units, which were ~~completed~~issued in connection with the IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. As of the closing of its IPO and through the date of this Quarterly Report, the Partnership did not own any working interests and did not have any ARO or any lease operating expenses as a working interest owner.

~~Table of Contents~~

~~KIMBELL ROYALTY PARTNERS, LP~~

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

~~(Unaudited)~~

Haymaker Acquisition.

NOTE 9—13—RELATED PARTY TRANSACTIONS

In connection with the IPO, the Partnership entered into a management services agreement with Kimbell Operating, which entered into separate ~~service~~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 (“Duncan Management”) pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective ~~service~~services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective ~~service~~services agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders. During the three and six months ended ~~September~~June 30, ~~2017,~~2019, no monthly services fee was paid to BJF Royalties or Steward Royalties. During the three months ended June 30, 2019, the Partnership made payments to ~~Steward Royalties,~~ Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of ~~$100,000, $100,000,~~$131,714, $30,000, ~~$125,884~~$81,918 and ~~$164,616,~~$124,576, respectively. During the ~~period from February 8, 2017 to September~~six months ended June 30, ~~2017,~~2019, the Partnership made payments to ~~Steward Royalties,~~ Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of ~~$266,667, $266,667, $80,000, $335,691~~$263,428, $60,000, $163,836 and ~~$438,975,~~$249,152, respectively. Certain consultants who provide services under ~~the above mentioned~~ management services agreements ~~were~~are granted restricted units under the Partnership’s ~~LTIP~~LTIP.

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

As of June 30, 2019, the Partnership had an outstanding receivable from a former employee of $86,747, which is included in accounts receivable and other current assets in the accompanying audited consolidated balance sheet. As of the filing of this Quarterly Report on ~~May 12, 2017.~~

~~During the Predecessor 2017 Period and the nine months ended September 30, 2016, the Predecessor Company’s activities included certain related party receivables and payables; however,~~Form 10-Q, all such amounts ~~were de minimis at December 31, 2016.~~have been collected from such employee by the Partnership.

NOTE ~~10—~~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 9―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 ~~11—~~15—COMMITMENTS AND CONTINGENCIES

~~Management~~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 ~~aware of any legal, environmental or other commitments or contingencies that would~~expected to have a material ~~effect~~impact on the Partnership’s condensed consolidated financial ~~condition, results~~statements, and no amounts have been accrued as of ~~operations or liquidity.~~June 30, 2019.

NOTE ~~12—~~16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to ~~September~~June 30, ~~2017~~2019 in the preparation of its condensed consolidated financial statements.

In July 2019, in connection with the Joint Venture, the Partnership paid capital contributions of $2.2 million.

On ~~October 27, 2017,~~July 29, 2019, Haymaker Minerals & Royalties, LLC exchanged 400,000 OpCo Common Units and Class B Units, together, for an equal number of common units of the Partnership.

On August 7, 2019, the Operating Company paid a quarterly cash distribution of $0.411452 to holders of OpCo Common Units. As to the Partnership, $0.021452 of the distribution corresponds to a tax payment made by the Partnership from cash reserves in the second quarter of 2019. The second quarter 2019 tax payment made by the Partnership 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, the Partnership is not reimbursed by the Operating Company for federal income taxes paid by the Partnership.

On August 9, 2019, the Partnership will pay a quarterly cash distribution on the Series A Preferred Units of $1.9 million for the quarter ended June 30, 2019.

On August 9, 2019, the Partnership will pay 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 $23,414 for the quarter ended June 30, 2019.

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

On July 26, 2019 the Board of Directors declared a quarterly cash distribution of ~~$0.31~~$0.39 per common unit for the quarter ended ~~September~~June 30, ~~2017.~~2019. The distribution will be paid on ~~November 13, 2017~~August 12, 2019 to common unitholders of record as of the close of business on ~~November 6, 2017.~~August 5, 2019.

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

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

1517

Table of Contents

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

The following discussion and analysis of financial condition and results of operations should be read together in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10‑Q (this “Quarterly Report”), as well as ~~the historical~~our audited financial statements ~~of our accounting predecessor for accounting~~ and ~~financial reporting purposes, Rivercrest Royalties, LLC, (“Rivercrest” or the “Predecessor”)~~notes thereto included in our Annual Report on Form ~~10‑K~~10-K for the year ended December 31, ~~2016.~~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, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units.~~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 ~~time~~closing of our IPO. ~~As a result, as of December 31, 2016, we had not yet acquired any of such assets.~~

~~Unless otherwise indicated in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the financial information presented~~ ~~for periods on or after February 8, 2017 refers~~References to the ~~Partnership as~~“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 ~~whole. The financial information presented for periods on or prior to February 7, 2017 refers only to Rivercrest, the predecessor for accounting purposes,~~ ~~and does not include the results~~wholly owned subsidiary of the Partnership as a whole. The interests underlying the oil, natural gas and natural gas liquids(“NGL”) production revenues of our Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.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,” ~~“assume,”~~ “forecast,~~” “position,~~” “predict,” “strategy,” “expect,” “intend,” ~~“plan,”~~ “estimate,” “anticipate,” “believe,~~” “project,” “budget,~~” “potential,” or “continue,” and similar expressions are used to identify forward‑looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward‑looking statements can be guaranteed. When considering these forward‑looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward‑looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such forward‑looking statements include:

our ability to replace our reserves;

our ability to 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;~~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;

~~our ability to replace our reserves;~~

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

general economic, business or industry conditions;

competition in the oil and natural gas industry;

~~Table of Contents~~

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

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

Table of Contents

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 ~~report.~~Quarterly Report.

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

Overview

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

As of ~~September~~June 30, ~~2017,~~2019, we owned mineral and royalty interests in approximately ~~3.7~~8.7 million gross acres and overriding royalty interests in approximately ~~2.0~~4.3 million gross acres, with approximately ~~35%~~48% of our aggregate acres located in the Permian ~~Basin.~~Basin and Mid-Continent. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of ~~September~~June 30, ~~2017,~~2019, over ~~95%~~98% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 2028 states and in ~~nearly~~ every major onshore basin across the continental United States and include ownership in over ~~50,000~~92,000 gross producing wells, including over ~~29,000~~40,000 wells in the Permian Basin.

1719

Table of Contents

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 June 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	1,572	1,311	40,191	27
Mid‑Continent	3,589,116	40,550	1,471	807	10,115	15
Haynesville	745,745	7,058	1,897	605	8,460	15
Appalachia	721,656	23,074	1,741	677	2,985	5
Bakken	1,555,557	5,959	494	424	3,801	14
Eagle Ford	532,142	6,282	1,342	1,062	2,394	6
Rockies	46,328	829	539	300	12,044	3
Other	3,222,614	36,829	2,751	1,454	12,921	4
Total	13,028,420	144,117	11,807	6,640	92,911	89

(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

InTransactions in Common Units

On April 10, 2019, Haymaker Minerals & Royalties, LLC exchanged 3,600,000 common units of the Operating Company ("OpCo Common Units") and common units representing limited partner interests of the Partnership ("Class B Units"), together, for an equal number of our common units.

On July 29, 2019, Haymaker Minerals & Royalties, LLC exchanged 400,000 OpCo Common Units and Class B Units, together, for an equal number of our common units.

Joint Venture

On June 19, 2019, we entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP. Our ownership in the Joint Venture is 49.3% and our 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. We have paid $2.2 million in capital contributions through the date of this report.

Commodity Derivative Instruments

On June 28, 2019, we entered into additional oil and natural gas fixed price swaps with Frost Bank for the second quarter of ~~2017,~~2021. The fixed price swaps consist of 59,423 Bbl of oil at a fixed rate of $54.52 per Bbl and 836,381 MMBtu of natural gas at a fixed rate of $2.43 per MMBtu.

Second Quarter Distributions

On August 7, 2019, the Operating Company paid a quarterly cash distribution of $0.411452 to holders of OpCo Common Units. As to the Partnership, ~~acquired mineral and royalty interests underlying 1.1~~$0.021452 of the distribution corresponds to a tax payment made by us from cash reserves in the second quarter of 2019. The second 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

Table of Contents

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 August 9, 2019, we will pay a quarterly cash distribution on the Series A Preferred Units of $1.9 million ~~gross acres, 6,881 net royalty acres,~~ for ~~an aggregate purchase price~~the quarter ended June 30, 2019.

On August 9, 2019, we will pay 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 ~~$16.8 million. The Partnership funded these acquisitions with borrowings under its revolving credit facility.~~$23,414 for the quarter ended June 30, 2019.

On ~~October 9, 2017,~~July 26, 2019 the ~~Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres,~~General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.39 per common unit for ~~an aggregate purchase price~~the quarter ended June 30, 2019. The distribution will be paid on August 12, 2019 to common unitholders of approximately $3.9 million in Uintah County, Utah. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility. The Partnership was required to put down a deposit which is included in depositsrecord as of the close of business on ~~oil and natural gas properties in the accompanying unaudited consolidated balance sheet at September 30, 2017.~~

August 5, 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. ~~In late 2014, prices for oil and natural gas declined precipitously, and prices remained low throughout 2015 and~~The table below demonstrates such volatility for the ~~majority of 2016 until rebounding in~~periods presented as reported by the ~~fourth quarter of 2016. During~~United States Energy Information Administration (“EIA”).


	Six Months Ended June 30, 2019				Six Months Ended June 30, 2018
	High		Low		High		Low
Oil ($/Bbl)	$	66.24	$	46.31	$	77.41	$	59.20
Natural gas ($/MMBtu)	$	4.25	$	2.27	$	6.24	$	2.49

On July 29, 2019, the ~~nine months ended September 30, 2017,~~ West Texas Intermediate (“WTI”) ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $54.48 per Bbl on February 23, 2017, and during the nine months ended September 30, 2016, WTI ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $51.23 per Bbl on June 8, 2016. During the nine months ended September 30, 2017, the Henry Hub spot market price of natural gas ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017. During the nine months ended September 30, 2016, the Henry Hub spot market price of natural gas ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $3.19 per MMBtu on September 21, 2016. On October 30, 2017, the WTI posted price for crude oil was ~~$54.11~~$56.85 per Bbl and the Henry Hub spot market price of natural gas was ~~$2.94~~$2.23 per MMBtu.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Oil ($/Bbl)	$	59.88	$	68.07	$	57.39	$	65.55
Natural gas ($/MMBtu)	$	2.57	$	2.85	$	2.74	$	2.96

Rig Count

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

For the three months ended September 30,

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

2017

2016

2017

2016
Oil (Bbl)

$
48.18

$
44.85

$
49.30

$
41.35
Natural gas (MMBtu)

$
2.95

$
2.88

$
3.01

$
2.34

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

~~Rig Count~~

The Baker Hughes ~~U.S.~~United States Rotary Rig count ~~was 940~~decreased by 7.6% from 1,047 active rigs ~~at September 29, 2017, an 80% increase from 522~~as of June 30, 2018 to 967 active rigs ~~at September~~as of June 30, ~~2016. In addition, according~~2019.

We own mineral and royalty interests in 28 states. According to the Baker Hughes ~~U.S.~~United States Rotary Rig count, rig activity in the 2028 states in which we own mineral and royalty interests ~~increased 83% from 468~~included 960 active rigs ~~at September~~as of June 30, ~~2016~~2019 compared to ~~857~~1,038 active rigs ~~at September 29, 2017.~~ as of June 30, 2018.

The active rig count across our acreage as of June 30, 2019 remained steady at ~~October 31, 2017 totaled 21~~89 active rigs ~~a 40% increase~~ compared to the 15active rigs at ~~year-end 2016.~~March 31, 2019. The 89 active rig count across our acreage as of June 30, 2019 increased significantly compared to the 25 active rigs as of June 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 additional mineral and royalty interests we acquired 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”) and the acquisition of

Table of Contents

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 third and fourth quarters of 2018, respectively.

Sources of Our Revenue

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

~~Table of Contents~~

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Royalty income
Oil sales	53	%	61	%	52	%	61	%
Natural gas sales	34	%	23	%	36	%	23	%
NGL sales	9	%	12	%	10	%	13	%
Lease bonus and other income	4	%	4	%	2	%	3	%
	100	%	100	%	100	%	100	%

We entered into ~~hedging arrangements~~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. ~~As a result, we may realize the benefit of any short‑term increase in the price of oil, natural gas~~

Non‑GAAP Financial Measures

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

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

~~Adjusted EBITDA~~

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

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

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

1922

Table of Contents

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


	Partnership		Predecessor		Partnership		Predecessor				Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended September 30,		Three Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,		Nine Months Ended September 30,		2019		2018		2019		2018
	2017		2016		2017		2017		2016
Net income (loss)	$	119,029	$	(769,166)	$	653,898	$	(496,856)	$	(6,018,014)
Depreciation, depletion and accretion expense		4,488,915		418,969		11,156,292		113,639		1,244,023
Reconciliation of net loss to Adjusted EBITDA:
Net (loss) income											$	(20,365,487)	$	1,378,295	$	(25,710,850)	$	(51,446,176)
Depreciation and depletion expense												12,311,443		3,431,594		22,592,451		7,887,302
Interest expense		225,302		103,596		468,429		39,307		314,081		1,441,651		483,558		2,864,214		833,600
State income taxes		—		4,212		—		—		13,401
Provision for income taxes												507,801		—		507,801		—
EBITDA		4,833,246		(242,389)		12,278,619		(343,910)		(4,446,509)		(6,104,592)		5,293,447		253,616		(42,725,274)
Impairment of oil and natural gas properties		—		306,959		—		—		4,992,897		28,146,711		—		30,948,909		54,753,444
Transaction costs												—		1,188,967		—		1,188,967
Unit‑based compensation		434,197		151,265		569,889		50,422		453,795		2,112,764		723,039		3,883,174		1,391,973
Adjusted EBITDA	$	5,267,443	$	215,835	$	12,848,508	$	(293,488)	$	1,000,183
Gain (loss) on commodity derivative instruments, net of settlements												(2,603,825)		469,072		2,562,059		681,530
Consolidated Adjusted EBITDA												21,551,058		7,674,525		37,647,758		15,290,640
Adjusted EBITDA attributable to noncontrolling interest												(10,940,971)		—		(20,347,981)		—
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP												10,610,087		7,674,525		17,299,777		15,290,640
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		166,707		219,900		276,246		34,505		280,010		582,829		502,811		1,207,118		977,487
Capital expenditures		—		—		—		—		—
Cash distributions on Series A preferred units												947,722		—		1,747,740		—
Cash income tax expense												504,000		—		504,000		—
Distributions on Class B units												23,814		—		47,628		—
Cash reserves												(504,000)		—		(504,000)		—
Cash available for distribution	$	5,100,736	$	(4,065)	$	12,572,262	$	(327,993)	$	720,173	$	9,055,722	$	7,171,714	$	14,297,291	$	14,313,153

Partnership

Predecessor

Partnership

Predecessor

Three Months Ended September 30,

Three Months Ended September 30,

Period from February 8, 2017 to September 30,

Period from January 1, 2017 to February 7,

Nine Months Ended September 30,

2017

2016

2017

2017

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

Net cash provided by operating activities

$
5,387,438

$
406,518

$
13,965,478

$
186,719

$
956,793
Interest expense

225,302

103,596

468,429

39,307

314,081
State income taxes

—

4,212

—

—

13,401
Impairment of oil and natural gas properties

—

(306,959)

—

—

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

(15,625)

(12,723)

(41,667)

(4,241)

(34,245)
Amortization of tenant improvement allowance

—

(32,603)

—

2,864

25,777
Unit-based compensation

(434,197)

(151,265)

(569,889)

(50,422)

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

Oil, natural gas and NGL revenues receivable

555,908

1,258,156

496,886

(14,551)

(11,258)
Other receivables

65,175

(1,246,269)

258,785

(333,056)

(1,246,269)
Accounts payable

228,080

(274,023)

(152,569)

(247,972)

1,071,453
Other current liabilities

(1,178,835)

8,971

(2,146,834)

77,442

(89,550)
EBITDA

$
4,833,246

$
(242,389)

$
12,278,619

$
(343,910)

$
(4,446,509)
Add:

Impairment of oil and natural gas properties

—

306,959

—

—

4,992,897
Unit‑based compensation

434,197

151,265

569,889

50,422

453,795
Adjusted EBITDA

$
5,267,443

$
215,835

$
12,848,508

$
(293,488)

$
1,000,183

2023

Table of Contents


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	23,332,182	$	6,894,754	$	39,144,514	$	14,188,843
Interest expense		1,441,651		483,558		2,864,214		833,600
Provision for income taxes		507,801		—		507,801		—
Impairment of oil and natural gas properties		(28,146,711)		—		(30,948,909)		(54,753,444)
Amortization of right-of-use assets		(11,374)		—		(22,578)		—
Amortization of loan origination costs		(260,422)		(15,625)		(518,149)		(31,250)
Unit-based compensation		(2,112,764)		(723,039)		(3,883,174)		(1,391,973)
Gain (loss) on commodity derivative instruments, net of settlements		2,603,825		(469,072)		(2,562,059)		(681,530)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(2,599,599)		37,453		(3,893,763)		(195,074)
Accounts receivable and other current assets		(167,330)		(144,931)		325,570		(10,032)
Accounts payable		257,657		(825,555)		949,806		(1,204,349)
Other current liabilities		(959,735)		55,904		(1,736,663)		519,935
Operating lease liabilities		10,227		—		27,006		—
EBITDA		(6,104,592)		5,293,447		253,616		(42,725,274)
Add:
Impairment of oil and natural gas properties		28,146,711		—		30,948,909		54,753,444
Transaction costs		—		1,188,967		—		1,188,967
Unit‑based compensation		2,112,764		723,039		3,883,174		1,391,973
Gain (loss) on commodity derivative instruments, net of settlements		(2,603,825)		469,072		2,562,059		681,530
Consolidated Adjusted EBITDA		21,551,058		7,674,525		37,647,758		15,290,640
Adjusted EBITDA attributable to noncontrolling interest		(10,940,971)		—		(20,347,981)		—
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP	$	10,610,087	$	7,674,525	$	17,299,777	$	15,290,640

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

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

~~No Effect Given~~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 ~~Transactions~~which (a) our equity interest in ~~Connection with Initial Public Offering~~

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 ~~historical financial statements~~Class B Units and OpCo Common Units are exchangeable together into an equal number of our ~~Predecessor included in this Quarterly Report do not reflect~~common units.

In May 2018, the ~~financial condition or results~~Board of ~~operations~~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 ~~Partnership. Further, these historical financial statements do not give effect~~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 ~~transactions that were completed in connection with~~Series A Preferred Units but prior to distributions on the ~~closing~~common units.

Table of Contents

Following the effectiveness of the ~~Partnership’s IPO. In connection with our IPO, our Predecessor assigned all of its non‑operating working interests to an affiliate that was not contributed to us,~~Tax Election and ~~all~~the completion of the ~~membership interests of~~related transactions, our ~~Predecessor were contributed~~royalty and minerals business continues to ~~us in exchange for common units and a portion of~~be conducted through the net proceeds from the IPO. In addition, the Contributing Parties directly or indirectly contributed to us the other assets that made up our initial assets in exchange for common units and a portion of the net proceeds from the IPO. The combination of the assets contributed to us by the Contributing Parties was accounted for at fair value as an asset acquisition. The fair value of the purchase price consideration was based upon the value of the common units purchased in the Partnership’s IPO by third-party investors.

The historical financial data of our Predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the PartnershipOperating Company, which is taxed as a ~~whole~~partnership for federal and may not provide an accurate indication of what our actual results would have been if the transactions completed in connection with our IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.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 $28.1 million for the three months ended June 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 ~~period from February 8, 2017 to September~~three months ended June 30, ~~2017. The substantial majority of~~2018. We recorded an impairment on our ~~proved~~ oil and natural gas properties ~~that were acquired at the time~~ of ~~the IPO were recorded at fair value~~$30.9 million and $54.8 million as a result of ~~the IPO. In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related~~our quarterly full-cost ceiling ~~limitation beyond a reasonable doubt~~analysis for the six months ended June 30, 2019 and ~~requested and received an exemption from~~2018, respectively. As discussed in our Annual Report on Form 10-K for the U.S. Securities and Exchange Commission (“SEC”) to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the periodyear ended ~~March 31, 2017 and will remain effective through all financial reporting periods through~~ December 31, ~~2017. A component~~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 ~~the exemption received from the SEC is that~~oil, natural gas and NGLs decreases in future periods, we ~~are~~may be required to ~~assess the fair value~~record additional impairments as a result of ~~these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in~~ the full-cost ceiling test would not be appropriate. As of September 30, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, we considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO

~~Table of Contents~~

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

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

Credit ~~Agreements~~Agreement

In connection with our IPO, on January 11, 2017, we entered into a ~~new~~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 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.

Table of Contents

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 order to include all assets acquired through the Phillips Acquisition in the borrowing base available under the Amended Credit Agreement, a borrowing base redetermination was completed in late May 2019. In connection with the 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 secured revolving credit facility matures on February 8, 2022.

As of ~~September~~June 30, ~~2017,~~2019, we had ~~borrowed $22.2~~approximately $87.3 million ~~to fund certain IPO-related transaction expenses,~~in borrowings outstanding under our entrance into a management services agreement with Kimbell Operating Company, LLC (“Kimbell Operating”) and the acquisition of mineral and royalty interests for an aggregate purchase price of approximately $20.7 million.senior secured credit facility. For the three months ended ~~September~~June 30, ~~2017~~2019 and ~~the period from February 8, 2017 to September 30, 2017,~~2018, we incurred ~~$225,302~~$1.4 million and ~~$468,429,~~$0.5 million, respectively, in interest expense. For the six months ended June 30, 2019 and 2018, we incurred $2.9 million and $0.8 million, respectively, in interest expense.

In January 2014, our Predecessor entered into a credit agreement with Frost Bank, as lender. For the Predecessor 2017 Period and the three and nine months ended September 30, 2016, our Predecessor’s interest expense was $39,307, $103,596 and $314,081, respectively. Our Predecessor had outstanding borrowings of $10.6 million as of December 31, 2016. We did not assume any indebtedness of our Predecessor in connection with the IPO.

Ongoing Acquisition ~~Opportunities~~Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from ~~our Sponsors, the Contributing Parties and~~ third ~~parties. We also may pursue acquisitions jointly with~~parties, affiliates of our Sponsors and the Contributing Parties. As a ~~consequence~~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 six months ended June 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 ~~such~~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 ~~acquisition‑related expense, the historical financial statements of our Predecessor will differ from our financial statements~~investments we make to be accretive in the ~~future.~~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.

Management Services Agreements

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

~~Non‑Operated Working Interest Assignment~~

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

2226

Table of Contents

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


	Partnership		Predecessor		Partnership		Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,		Nine Months Ended September 30,		Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2017		2016		2019		2018		2019		2018
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	8,351,399	$	969,084	$	20,656,741	$	318,310	$	2,572,477	$	27,913,975	$	10,847,677	$	50,747,368	$	21,655,856
Lease bonus and other income												1,289,044		398,610		1,372,650		766,734
Gain (loss) on commodity derivative instruments, net												2,733,582		(538,389)		(2,236,208)		(823,354)
Total revenues												31,936,601		10,707,898		49,883,810		21,599,236
Costs and expenses
Production and ad valorem taxes		778,733		120,315		1,602,520		19,651		203,567		1,924,943		805,396		3,521,337		1,621,397
Depreciation, depletion and accretion expense		4,488,915		418,969		11,156,292		113,639		1,244,023
Depreciation and depletion expense												12,311,443		3,431,594		22,592,451		7,887,302
Impairment of oil and natural gas properties		—		306,959		—		—		4,992,897		28,146,711		—		30,948,909		54,753,444
Marketing and other deductions		424,702		320,698		1,068,509		110,534		570,521		1,749,040		609,033		3,606,083		1,178,875
General and administrative expenses		2,314,718		463,501		5,707,093		532,035		1,252,001		6,220,499		4,000,022		11,553,865		6,770,794
Total costs and expenses		8,007,068		1,630,442		19,534,414		775,859		8,263,009		50,352,636		8,846,045		72,222,645		72,211,812
Operating income (loss)		344,331		(661,358)		1,122,327		(457,549)		(5,690,532)
Operating (loss) income												(18,416,035)		1,861,853		(22,338,835)		(50,612,576)
Other expense
Interest expense		225,302		103,596		468,429		39,307		314,081		1,441,651		483,558		2,864,214		833,600
Income (loss) before income taxes		119,029		(764,954)		653,898		(496,856)		(6,004,613)
State income taxes		—		4,212		—		—		13,401
Net income (loss)	$	119,029	$	(769,166)	$	653,898	$	(496,856)	$	(6,018,014)
Net (loss) income before income taxes												(19,857,686)		1,378,295		(25,203,049)		(51,446,176)
Provision for income taxes												507,801		—		507,801		—
Net (loss) income												(20,365,487)		1,378,295		(25,710,850)		(51,446,176)
Distribution and accretion on Series A preferred units												(3,469,584)		—		(6,939,168)		—
Net loss attributable to noncontrolling interests												12,100,511		—		17,252,020		—
Distribution on Class B units												(23,814)		—		(47,628)		—
Net (loss) income attributable to common units											$	(11,758,374)	$	1,378,295	$	(15,445,626)	$	(51,446,176)
Production Data:
Oil (Bbls)		108,692		13,752		267,966		3,696		41,548		268,963		108,201		495,564		218,087
Natural gas (Mcf)		888,694		93,794		2,205,292		32,961		343,078		4,030,160		999,019		7,366,883		1,983,385
Natural gas liquids (Bbls)		46,493		4,850		108,929		1,220		17,458		133,749		55,917		253,904		110,500
Combined volumes (Boe) (6:1)		303,301		34,234		744,444		10,410		116,186		1,074,405		330,621		1,977,282		659,151

Comparison of the Three Months Ended ~~September~~June 30, ~~2017~~2019 to the Three Months Ended ~~September~~June 30, ~~2016~~

The period presented for the three months ended September 30, 2017 and 2016 includes the results of operations of the Partnership and our Predecessor, respectively. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.2018

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

For the three months ended ~~September~~June 30, ~~2017,~~2019, our oil, natural gas and NGL revenues were ~~$8.4~~$27.9 million, an increase of ~~$7.4~~$17.1 million from ~~$1.0~~$10.8 million for the three months ended ~~September~~June 30, ~~2016.~~2018. The increase in revenues was primarily ~~due~~attributable to the ~~$247.8~~revenues associated with the Haymaker Acquisition, which represented approximately $10.1 million ~~acquisition~~ of ~~various mineral~~the overall increase in oil, natural gas and ~~royalty interests from~~NGL revenues, and to a lesser extent, the ~~Contributing Parties at~~revenues associated with the ~~closing of our IPO~~Phillips Acquisition and Dropdown which contributed $5.4 million and $2.9 million, respectively, to the ~~relevant production~~overall increase. Partially offsetting the increase in oil, natural gas and NGL revenues, ~~from those acquired interests.~~was a decrease in the average prices we received for oil and NGL production.

2327

Table of Contents

Our ~~and our Predecessor’s~~ revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were ~~303,301~~1,074,405 Boe or ~~3,297~~11,807 Boe/d, for the three months ended ~~September~~June 30, ~~2017,~~2019, an increase of ~~269,067~~743,784 Boe or ~~2,925~~8,174 Boe/d, from ~~34,234~~330,621 Boe or ~~372~~3,633 Boe/d, for the three months ended ~~September~~June 30, ~~2016.~~2018. The increase in production ~~realized from~~was primarily attributable to the ~~overriding royalty interests we acquired from Maxus Energy Corporation in late April 2017 enabled us to offset natural production declines from our existing portfolio~~Haymaker Acquisition, which represented 485,138 Boe or 5,331 Boe/d, and to ~~exit~~a lesser extent, production associated with the ~~quarter ended September 30, 2017 with slightly higher production.~~Phillips Acquisition and Dropdown, which together accounted for 281,783 Boe or 3,097 Boe/d.

Our operators received an average of ~~$43.95~~$57.55 per Bbl of oil, ~~$2.79~~$2.44 per Mcf of natural gas and ~~$19.75~~$19.55 per Bbl of NGL for the volumes sold during the three months ended ~~September~~June 30, ~~2017. Our Predecessor’s operators received an average of $42.08~~2019 and $63.45 per Bbl of oil, ~~$3.11~~$2.59 per Mcf of natural gas and ~~$20.37~~$25.03 per Bbl of NGL for the volumes sold during the three months ended ~~September~~June 30, ~~2016.~~2018. The three months ended ~~September~~June 30, ~~2017 increased 4.4%~~2019 decreased 9.3% or ~~$1.87~~$5.90 per Bbl of oil and ~~decreased 10.3%~~5.8% or ~~$0.32~~$0.15 per Mcf of natural gas as compared to the three months ended ~~September~~June 30, ~~2016. The increase in the average price received for oil~~2018. This change is consistent with ~~increase in the price of oil~~prices experienced in the market, specifically when compared to the EIA average price ~~increase~~decreases of ~~7.4%~~12.0% or ~~$3.33~~$8.19 per Bbl of ~~oil. The change~~oil and 9.8% or $0.28 per Mcf of natural gas for the comparable periods.

Gain on Commodity Derivative Instruments

Gain on commodity derivative instruments for the three months ended June 30, 2019 included $2.6 million of mark-to-market gains and $0.1 million of gains on the settlement of commodity derivative instruments compared to $0.5 million of mark-to-market losses and $0.1 million loss on the settlement of commodity derivative instruments for the three months ended June 30, 2018. We recorded a mark-to-market gain for the three months ended June 30, 2019 as a result of the decrease in the ~~average~~ price ~~received for~~of oil and natural gas ~~was attributable~~contracts relative to the ~~diversification of~~fixed-price in our ~~natural gas producing interests when compared to the natural gas producing interests of our Predecessor.~~open derivative contracts.

Production and Ad Valorem Taxes

~~Our production~~Production and ad valorem taxes increased significantly for the three months ended ~~September~~June 30, ~~2017 were~~2019 for a total of $1.9 million compared to $0.8 million ~~an increase of $0.7 million from $0.1 million in~~for the three months ended ~~September~~June 30, ~~2016.~~2018. The increase was primarily attributable to the Haymaker Acquisition, which accounted for $0.5 million of the increase in production and ad valorem taxes ~~was attributable~~and, to the ~~$247.8 million acquisition of various mineral~~lesser extent, the Dropdown and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.~~Phillips Acquisition.

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

~~Our depreciation,~~Depreciation and depletion ~~and accretion~~ expense for the three months ended ~~September~~June 30, ~~2017~~2019 was ~~$4.5~~$12.3 million, an increase of ~~$4.1~~$8.9 million from ~~our Predecessor’s depreciation, depletion and accretion expense of $0.4~~$3.4 million for the three months ended ~~September~~June 30, ~~2016.~~2018. The increase in the depreciation ~~depletion~~ and ~~accretion~~depletion expense was primarily attributable to the ~~$247.8 million acquisition of various mineral and royalty interests from~~Haymaker Acquisition, the ~~Contributing Parties at the closing of our IPO~~Dropdown and the ~~relevant production from those acquired properties.~~Phillips Acquisition, which together added approximately $349.1 million of depletable costs to the full-cost pool.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

We recorded an impairment expense on our oil and natural gas properties of $28.1 million during the three months ended June 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~~June 30, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment of oil and natural gas properties for the Partnership in the current period. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired.

~~Impairments for our Predecessor totaled $0.3 million for the three months ended September 30, 2016 primarily due to the impact that declines in commodity prices had on the value of reserve estimates.~~2018.

Marketing and Other Deductions

2428

Table of Contents

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

General and Administrative Expenses

~~Our general~~General and administrative expenses for the three months ended ~~September~~June 30, ~~2017~~2019 were ~~$2.3~~$6.2 million, an increase of ~~$1.8~~$2.2 million from ~~our Predecessor’s~~$4.0 million for the three months ended June 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 $1.4 million increase in unit-based compensation expense, which included $0.3 million in unit-based compensation expense related to one-time severance costs incurred during the quarter. General and administrative expenses were also impacted by $0.1 million in cash expenses related to one-time severance costs incurred during the quarter. The remainder of the increase was primarily attributable to cash general and administrative expenses resulting from the Haymaker Acquisition, Dropdown and Phillips Acquisition.

Interest Expense

Interest expense for the three months ended June 30, 2019 was $1.4 million as compared to interest expense of $0.5 million for the three months ended ~~September~~June 30, ~~2016. The~~2018. This increase was due to debt incurred to fund acquisitions in ~~general and administrative expenses was attributable to~~2018, including the ~~increased cost related to operating the Partnership as~~Haymaker Acquisition.

Provision for Income Taxes

We recorded a ~~publicly traded company.~~

~~Interest Expense~~

~~Our interest expense~~provision for ~~the three months ended September 30, 2017 was $0.2 million as compared to our Predecessor’s interest expense~~income taxes of ~~$0.1~~$0.5 million for the three months ended ~~September~~June 30, ~~2016.~~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. Prior to the third quarter of 2018, we had no provision for or benefit from income taxes. 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 June 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~~Six Months Ended ~~September~~June 30, ~~2017~~2019 to the ~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~

The period presented for the nine months ended September 30, 2017 includes the results of operations of our Predecessor for the Predecessor 2017 Period and our results of operations for the period from February 8, 2017 to September 30, 2017. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.2018

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

For the ~~period from February 8, 2017 to September~~six months ended June 30, ~~2017~~2019, our oil, natural gas and ~~the Predecessor 2017 Period, our and our Predecessor’s~~NGL revenues were ~~$20.7 and $0.3~~$50.7 million, ~~respectively, for combined revenues~~an increase of ~~$21.0~~$29.0 million from $21.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017, an increase of $18.4 million, from $2.6 million for the nine months ended September 30, 2016.~~2018. The increase in revenues was primarily ~~due~~attributable to the ~~$247.8~~revenues associated with the Haymaker Acquisition, which represented approximately $20.1 million ~~acquisition~~ of ~~various mineral~~the overall increase in oil, natural gas and ~~royalty interests from~~NGL revenues, and to a lesser extent, the ~~Contributing Parties at~~revenues associated with the ~~closing of our IPO~~Phillips Acquisition and Dropdown, which contributed $10.8 million and $5.9 million, respectively, to the ~~relevant production~~overall increase. Partially offsetting the increase in oil, natural gas and NGL revenues, ~~from those acquired interests.~~was a decrease in the average prices we received for oil and NGL production.

Our ~~and our Predecessor’s~~ revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were ~~744,444~~1,977,282 Boe or ~~3,168 Boe/d and 10,410 Boe or 274~~10,924 Boe/d, for the ~~period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period, respectively. The combined production for the nine~~six months ended ~~September~~June 30, ~~2017 was 754,854 Boe or 2,765 Boe/d,~~2019, an increase of ~~638,668~~1,318,131 Boe or ~~2,341~~7,282 Boe/d, from ~~116,186~~659,151 Boe or ~~424~~3,642 Boe/d, for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2018. The increase in production ~~realized from~~was primarily attributable to the ~~overriding royalty interests we acquired from Maxus Energy Corporation in late April 2017 enabled us to offset natural production declines from our existing portfolio~~Haymaker Acquisition, which represented 948,043 Boe or 5,238 Boe/d, and to ~~exit~~a lesser extent, production associated with the ~~quarter ended September 30, 2017 with slightly higher production.~~Phillips Acquisition and Dropdown, which together accounted for 570,064 Boe or 3,150 Boe/d.

Our operators received an average of ~~$45.14~~$54.51 per Bbl of oil, ~~$2.77~~$2.55 per Mcf of natural gas and ~~$20.85~~$19.62 per Bbl of NGL for the volumes sold during the ~~period from February 8, 2017 to September~~six months ended June 30, ~~2017. Our Predecessor’s operators received an average of $47.04~~2019 and $62.20 per Bbl of oil, ~~$3.47~~$2.64 per Mcf of natural gas and ~~$24.61~~$25.85 per Bbl of NGL for the volumes sold during the ~~Predecessor 2017 Period. For the combined nine~~six months ended ~~September~~June 30, ~~2017, the operators received an average of $45.16~~2018. The six months ended June 30, 2019 decreased 12.4% or $7.69 per Bbl of oil ~~$2.78~~and 3.4% or $0.09 per Mcf of natural gas and $20.90 per Bbl of NGL for the volumes sold. Our Predecessor’s operators received an average of $38.11 per Bbl of oil, $2.14 per Mcf of natural gas and $14.56 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2016. Average prices received by the operators during the combined nine months ended September 30, 2017 increased 18.5% or $7.05 per Bbl of oil and 29.9% or $0.64 per Mcf of natural gas as compared to the ~~nine~~six months ended ~~September~~June 30, ~~2016. These increases are~~2018. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price ~~increases~~decrease of ~~19.2%~~12.4% or ~~$7.95~~$8.16 per Bbl of oil and ~~28.6%~~7.4% or ~~$0.67~~$0.22 per Mcf of natural gas for the comparable periods.

2529

Table of Contents

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the six months ended June 30, 2019 included $2.6 million of mark-to-market losses and $0.3 million of gains on the settlement of commodity derivative instruments compared to $0.7 million of mark-to-market losses and $0.1 million loss on the settlement of commodity derivative instruments for the six months ended June 30, 2018. We recorded a mark-to-market loss for the six months ended June 30, 2019 as a result of the increase in volumes hedged due to Haymaker Acquisition, partially offset by the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts.

Production and Ad Valorem Taxes

~~Our production~~Production and ad valorem taxes increased significantly for the ~~period from February 8, 2017~~six months ended June 30, 2019 for a total of $3.5 million compared to ~~September 30, 2017 and the Predecessor 2017 Period were~~ $1.6 million ~~and $0.02 million, respectively. The combined production and ad valorem taxes~~ for the ~~nine~~three months ended ~~September~~June 30, ~~2017 were $1.6~~2018. The increase was primarily attributable to the Haymaker Acquisition, which accounted for $0.9 million ~~an increase~~ of ~~$1.4 million from $0.2 million in~~ the ~~nine months ended September 30, 2016. The~~ increase in production and ad valorem taxes ~~was attributable~~and, to the ~~$247.8 million acquisition of various mineral~~lesser extent, the Dropdown and ~~royalty interests from the Contributing Parties at the closing of our IPO and the relevant production and revenues from those acquired interests.~~Phillips Acquisition.

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

~~Our~~Depreciation and ~~our Predecessor’s depreciation,~~ depletion ~~and accretion~~ expense for the ~~period~~six months ended June 30, 2019 was $22.6 million, an increase of $14.7 million from ~~February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period was $11.2 million and $0.1 million respectively for a combined expense of $11.3~~$7.9 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017. This was an increase of $10.1 million from our Predecessor’s depreciation, depletion and accretion expense of $1.2 million for the nine months ended September 30, 2016.~~2018. The increase in the depreciation ~~depletion~~ and ~~accretion~~depletion expense was primarily attributable to the ~~$247.8 million acquisition of various mineral and royalty interests from~~Haymaker Acquisition, the ~~Contributing Parties at the closing of our IPO~~Dropdown and the ~~relevant production from those acquired properties.~~Phillips Acquisition, which together added approximately $349.1 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 ~~producing~~ reserves are a major component in the calculation of depletion. Our ~~and our Predecessor’s~~ average depletion rate per barrel was ~~$14.84 and $10.31~~$11.42 for the ~~period~~six months ended June 30, 2019, a decrease of $0.41 per barrel from ~~February 8, 2017 to September 30, 2017 and~~ the ~~Predecessor 2017 Period, respectively. The combined~~$11.83 average depletion rate per barrel for the ~~nine~~six months ended ~~September~~June 30, ~~2017 was $14.78, an increase of $4.07 per barrel from an average depletion rate of $10.71 per barrel for the nine months ended September 30, 2016.~~2018. The ~~increase in the average depletion rate per barrel~~decrease was primarily attributable to the ~~$247.8~~$54.8 million ~~acquisition~~ of ~~various mineral~~impairment recorded on our oil and ~~royalty interests from~~natural gas properties during the ~~Contributing Parties at the closing of our IPO and the relevant production from those acquired properties.~~six months ended June 30, 2018.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

NoWe recorded an impairment expense was recorded for the period from February 8, 2017 to September 30, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment ofon our oil and natural gas properties ~~for~~of $30.9 million and $54.8 million during the Partnership for the period from February 8, 2017 to September 30, 2017. Unless there are significant changes in oil and gas prices or the Partnership’s oil and gas reserves, it is likely the Partnership will recognize an impairment in 2018 after the exemption has expired.

~~Impairments for our Predecessor totaled $5.0 million for the nine~~six months ended ~~September~~June 30, ~~2016 primarily due to the impact that declines in commodity prices had on the value~~2019 and 2018, respectively, as a result of ~~reserve estimates.~~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, and our Predecessor’s marketing and other deductions also include lease operating expenses related to its non‑operated working interests.~~expense. Marketing and other deductions for the ~~period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $1.1 million and $0.1 million, respectively. The combined marketing and other deductions for the nine~~six months ended ~~September~~June 30, ~~2017~~2019 were ~~$1.2~~$3.6 million, an increase of ~~$0.6~~$2.4 million from ~~our Predecessor’s marketing and other deductions~~$1.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016 of $0.6 million.~~2018. The increase in marketing and other deductions was primarily attributable to the ~~$247.8~~Haymaker Acquisition, which represents $1.6 million ~~acquisition~~ of ~~various mineral~~the overall increase, and ~~royalty interests from~~to a lesser extent, the ~~Contributing Parties at the closing of our IPO~~Dropdown and the ~~relevant production and revenues from those acquired interests.~~Phillips Acquisition.

General and Administrative Expenses

~~Our and our Predecessor’s general~~General and administrative expenses for the ~~period~~six months ended June 30, 2019 were $11.6 million, an increase of $4.8 million from ~~February 8, 2017~~$6.8 million for the six months ended June 30, 2018. The increase in general and administrative expenses was primarily attributable the $2.5 million increase in unit-based compensation expense. The remainder of the increase was primarily attributable to ~~September 30, 2017~~cash general and administrative expenses resulting from the ~~Predecessor 2017 Period were $5.7 million~~Haymaker Acquisition, Dropdown and ~~$0.5 million, respectively. General and administrative~~Phillips Acquisition.

2630

Table of Contents

expenses for the combined nine months ended September 30, 2017 were $6.2 million, an increase of $4.9 million from our Predecessor’s general and administrative expenses of $1.3 million for the nine months ended September 30, 2016. The increase in general and administrative expenses was attributable to the increased costs related to operating the Partnership as a publicly traded company.

Interest Expense

~~Our and our Predecessor’s interest~~Interest expense for the ~~period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period was $0.5 million and $0.04 million, respectively. The interest expense for the combined nine~~six months ended ~~September~~June 30, ~~2017~~2019 was ~~$0.5~~$2.9 million as compared to ~~our Predecessor’s~~ interest expense of ~~$0.3~~$0.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~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 $0.5 million for the six months ended June 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. Prior to the third quarter of 2018, we had no provision for or benefit from income taxes. 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 June 30, 2019, we recorded a full valuation allowance on our deferred tax assets. See Note 12—Income Taxes for further discussion.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations and equity and debt financings and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. ~~We have~~On July 12, 2018, we entered into ~~a $50.0 million~~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 ~~$100.0~~$500.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), to ~~initially~~ be used for general partnership purposes, including working capital and acquisitions, ~~and certain IPO-related transaction expenses.~~among other things. In connection with the ~~August 1~~ redetermination ~~under the secured revolving credit facility,~~of the borrowing base ~~was reaffirmed at $100.0 million. Aggregate~~in May 2019, total commitments ~~remain at $50.0 million, providing for maximum availability~~ under the ~~secured revolving credit facility of $50.0~~Amended Credit Agreement were increased from $200.0 million to $225.0 million. As of ~~November 8, 2017,~~August 2, 2019, we had an outstanding balance of ~~$29.6~~$87.3 million under our secured revolving credit facility.

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

~~Unlike a number of other master limited partnerships, we~~ We do not ~~generally~~currently intend to ~~retain~~maintain a material reserve of cash ~~from~~for the purpose of maintaining stability or growth in our ~~operations for capital expenditures necessary~~quarterly distribution, nor do we intend to ~~replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due~~incur debt to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. If they believe it is warranted,pay quarterly distributions, although the Board of Directors may withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the period(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders.change this policy.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt ~~securities, although~~securities. For example, we 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. ~~We do not currently intend to maintain excess distribution coverage for~~

Table of Contents

Because the ~~purpose~~limited liability company agreement of ~~maintaining stability or growth in our quarterly distribution or otherwise reserve cash for distributions, or to incur debt to pay quarterly distributions, although~~ the ~~Board of Directors may do so if they believe it is warranted.~~

~~Because~~Operating Company and our partnership agreement ~~requires~~each require the Operating Company and us to distribute an amount equal to all available cash ~~we generate~~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 ~~our~~ quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price

~~Table of Contents~~

of oil, natural gas and ~~natural gas liquids,~~NGLs, changes to working capital or capital expenditures, (iii) tax and ~~(iii)~~certain contractual obligations and (iv) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of ~~our~~ quarterly distributions may be significant and could result in ~~our not making any~~no distribution being made for any particular quarter. We ~~will~~do not ~~have a minimum~~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 ~~employ structures intended~~(iii) incur debt to ~~consistently maintain or increase~~pay quarterly distributions, ~~over time. The~~although the Board of Directors may ~~change our distribution policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters.~~do so if they believe it is warranted.

On ~~May 2, 2017,~~August 7, 2019, the Operating Company paid a quarterly cash distribution of $0.411452 to holders of OpCo Common Units. As to the Partnership, $0.021452 of the distribution corresponds to a tax payment made by us from cash reserves in the second quarter of 2019. The second 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 August 9, 2019, we will pay a quarterly cash distribution on the Series A Preferred Units of $1.9 million for the quarter ended June 30, 2019.

On August 9, 2019, we will pay 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 $23,414 for the quarter ended June 30, 2019.

On July 26, 2019 the Board of Directors declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The Partnership’s calculated cash available for distribution was $0.18 per common unit for the quarter. However, during the period ended March 31, 2017, pursuant to the contribution agreement entered into by the Contributing Parties prior to the IPO, the Partnership received cash from the Contributing Parties for oil, natural gas and NGL production for periods prior to the IPO. The Board of Directors voted to distribute an additional $0.05 per common unit. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

~~On July 28, 2017, the Board of Directors declared a quarterly cash distribution of $0.30~~$0.39 per common unit for the quarter ended June 30, 2017. The Partnership’s calculated cash available for distribution was $0.28 per common unit for the quarter. The Board of Directors voted to distribute an additional $0.02 per common unit due to excess working capital generated primarily from positive prior period production from our operators.2019. The distribution ~~was~~will be paid on August ~~14, 2017~~12, 2019 to common unitholders and OpCo common unitholders of record as of the close of business on August ~~7, 2017.~~

On October 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended September 30, 2017. The distribution will be paid on November 13, 2017 to unitholders of record as of the close of business on November 6, 2017.5, 2019.

Cash Flows

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


	Partnership		Predecessor
	Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,		Nine Months Ended September 30,		Six Months Ended June 30,
	2017		2017		2016		2019		2018
Cash Flow Data:
Cash flows provided by operating activities	$	13,965	$	187	$	957	$	39,144,514	$	14,188,843
Cash flows used in investing activities		(117,190)		(1)		(94)		(1,405,311)		(10,477,294)
Cash flows provided by (used in) financing activities		109,451		—		(563)
Cash flows used in financing activities								(36,625,419)		(1,002,412)
Net increase in cash	$	6,226	$	186	$	300	$	1,113,784	$	2,709,137

Operating Activities

Our ~~and our Predecessor’s~~ operating cash flow is impacted by many variables, the most significant of which isare 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 ~~NGL.~~NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our ~~and our Predecessor’s~~ control and are difficult to predict. Cash flows provided by operating activities for the ~~period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period were $14.0 million and $0.2 million, respectively. Cash flows provided by operating activities for the combined nine~~six months ended ~~September~~June 30, ~~2017~~2019 were ~~$14.2~~$39.1 million, an increase of ~~$13.2~~$24.9 million compared to ~~our Predecessor’s~~$14.2 million for the six months ended June 30, 2018. The increase in cash flows provided by operating activities ~~of $1.0 million for the nine months ended September 30, 2016. The increase~~ was ~~largely~~primarily attributable to the ~~$247.8 million acquisition~~Haymaker Acquisition and Dropdown in the third and fourth quarters of ~~various mineral~~2018, respectively, and ~~royalty interests from~~to the ~~Contributing Parties at~~Phillips Acquisition in the ~~closing~~first quarter of ~~our IPO and the relevant production and revenues from those acquired interests.~~2019.

2832

Table of Contents

Investing Activities

Cash flows used in investing activities for the ~~period from February 8, 2017 to September~~six months ended June 30, ~~2017 were $117.2 million, an increase of $117.1~~2019 decreased by $9.1 million compared to ~~our Predecessor’s cash flows used in investing activities for~~ the ~~nine~~six months ended ~~September~~June 30, ~~2016 of $0.1 million. Our Predecessor’s cash flows used in investing activities were de minimis for the Predecessor 2017 Period.~~2018. For the ~~period from February 8, 2017 to September~~six months ended June 30, ~~2017,~~2019, we used $1.0 million to fund the ~~$96.2~~Phillips Acquisition and $0.4 million to fund the remodel of office space. For the six months ended June 30, 2018 we used $21.0 million to fund the deposit on the Haymaker Acquisition, partially offset by $10.6 million in proceeds received from ~~our IPO to pay~~ the ~~cash portion of our acquisition~~sale of oil and natural gas ~~properties at the IPO and we used $20.7 million to fund the acquisition of various mineral and royalty interests.~~properties.

Financing Activities

Cash flows ~~provided by financing activities was $109.5 million for the period from February 8, 2017 to September 30, 2017 as compared to our Predecessor’s cash~~ used in financing activities ~~of $0.6~~were $36.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016. Our Predecessor did not have any cash~~2019, an increase of $35.6 million compared to $1.0 million for the six months ended June 30, 2018. Cash flows used in ~~or provided by~~ financing activities for the ~~Predecessor 2017 Period. During the period from February 8, 2017~~six months ended June 30, 2019 consists of $36.3 million of distributions paid to ~~September 30, 2017, we received $96.2~~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 $0.5 million in ~~proceeds~~contributions from our ~~IPO, we borrowed $22.2 million, paid a distribution to unitholders of $8.7 million and paid loan origination costs of $0.3 million. During~~Class B unitholders. Cash flows used in financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2018 consists of $13.1 million of distributions paid to common unitholders and $6.9 million of repayments on our ~~Predecessor repaid $0.6~~secured revolving credit facility, offset by $19.0 million ~~on its long‑term debt.~~of additional borrowings under our secured revolving credit facility.

Capital Expenditures

During the ~~period from February 8, 2017 to September~~six months ended June 30, ~~2017,~~2019, we ~~acquired mineral and royalty interests from the Contributing Parties for common units with a total value at the IPO of $169.1 million and $96.2~~paid approximately $1.0 million in ~~cash. Additionally, we spent an aggregate amount of $20.7 million for~~connection with the ~~acquisition of various mineral and royalty interests.~~Phillips Acquisition. During the Predecessor 2017 Period, our Predecessor spent $523 on additional lease and well equipment and intangible drilling costs related to the Predecessor’s working interests and office equipment. During the ninesix months ended ~~September~~June 30, ~~2016, our Predecessor spent $0.1~~2018, we paid a $21.0 million ~~on additional lease and well equipment and intangible drilling costs related to~~deposit in connection with the ~~Predecessor’s working interests and office equipment.~~Haymaker Acquisition.

Indebtedness

~~Revolving Credit Agreement~~

~~We entered into a $50.0 million revolving credit facility in~~In connection with our IPO, ~~which is secured by substantially all~~on January 11, 2017, we entered into the 2017 Credit Agreement with Frost Bank. In connection with the closing of ~~our assets and~~ the ~~assets of our wholly owned subsidiaries.~~Haymaker Acquisition, we entered into the Credit Agreement Amendment. Under the Amended Credit Agreement, availability under our secured revolving credit facility ~~availability under the facility~~ will continue to equal the lesser of the aggregate maximum 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 ~~re-determined~~redetermined semi-annually ~~on February~~November 1 and ~~August~~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 order to include all assets acquired through the Phillips Acquisition in the borrowing base available under the Amended Credit Agreement, a borrowing base redetermination was completed in late May 2019. In connection with the 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 ~~secured revolving credit facility~~Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased up to ~~$100.0~~$500.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. In connection with the August 1 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0 million.

The ~~secured revolving credit facility~~Amended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The ~~secured revolving credit facility~~Amended Credit Agreement also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The ~~secured revolving credit facility~~Amended Credit Agreement also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control. As of ~~November 8, 2017,~~June 30, 2019, we ~~have borrowed $29.6~~had outstanding borrowings of $87.3 million ~~to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC~~under the secured revolving credit facility and ~~the acquisition~~$212.7 million of ~~various mineral and royalty interests for an aggregate purchase price of approximately $28.1 million.~~available capacity.

2933

Table of Contents

~~Predecessor~~For additional information on our Amended Credit ~~Facility~~

~~On January 31, 2014, our Predecessor entered into a credit agreement with Frost Bank for a $50.0 million credit facility. The credit facility was subject~~Agreement, please read Note 7―Long-Term Debt to ~~borrowing base restrictions and was collateralized by certain properties. The borrowing base was $20 million with interest payable monthly on Alternate Base Rate loans or at~~ the end of the interest period on any Eurodollar loans. As of December 31, 2016, our Predecessor’s total indebtedness under its credit facility was approximately $10.6 million, with an average interest rate of 3.39%. The credit facility was to mature in January 2018. The credit facility contained certain restrictive covenants. As of December 31, 2016, the Predecessor was in compliance with all of the covenantsunaudited condensed consolidated financial statements included in the credit facility. On February 8, 2017, our Predecessor repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the contribution of our Predecessor’s mineral and royalty interests to the Partnership. We did not assume any indebtedness of our Predecessor in connection with the IPO.

~~Internal Controls and Procedures~~

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

Further, our independent registered public accounting firm is not yet required to attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the Jumpstart Our Business Act (“JOBS Act”) or as long as we are a non‑accelerated filer.this Quarterly Report.

New and Revised Financial Accounting Standards

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

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

Critical Accounting Policies and Related Estimates

The discussion and analysis of our financial condition and results of operations are based upon the historical financial statements of our Predecessor, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

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

~~Table of Contents~~

~~Inflation~~

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

~~Off‑Balance Sheet Arrangements~~

~~As of September 30, 2017, neither we, nor our Predecessor had any off‑balance sheet arrangements other than operating leases. As of September 30, 2017, there~~There have been no ~~significant~~substantial changes to our ~~contractual obligations~~critical accounting policies and related estimates from those previously disclosed in ~~the Partnership’s~~our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2018.

Contractual Obligations and Off‑Balance Sheet Arrangements

There have been no changes to our contractual obligations previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018. As of June 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 for production depend on many factors outside of our or their control. ~~Currently,~~To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The 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 ~~have any commodity hedges in place but may~~require our counterparties to our derivative contracts to post collateral, we do ~~so in~~evaluate the ~~future if the Board~~credit standing of ~~Directors decides doing so~~such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of June 30, 2019, we had one counterparty, which is ~~in the best interest~~also one of the ~~Partnership.~~

~~Credit Risk~~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.

Table of Contents

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of ~~September~~June 30, ~~2017,~~2019, we had total borrowings outstanding under our secured revolving credit facility of ~~$22.2~~$87.3 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 ~~$0.2~~$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 ~~SEC.~~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~~June 30, ~~2017.~~2019.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended ~~September~~June 30, ~~2017~~2019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

3135

Table of Contents

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

~~Although we may, from time~~For a description of the Partnership’s legal proceedings, see Note 15—Commitments and Contingencies to ~~time, be involved in various legal claims arising out of our operations in~~ the ~~normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our~~condensed consolidated financial ~~condition, cash flows or results of operations.~~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 ~~2016~~ Annual Report on Form ~~10-K.~~10-K for the year ended December 31, 2018. There have been no material changes to the risk factors previously discussed in Item ~~1A—~~1A. Risk Factors in the Partnership’s ~~2016~~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 April 10, 2019, we issued 3,600,000 common units to Haymaker Minerals & Royalties, LLC in exchange for 3,600,000 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 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.

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

The following table provides information about purchases of our common units during the three months ended June 30, 2019.


Period	Total Number of Common Units Purchased(1)	Average Price Paid per Common Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs(2)	Maximum Number of Common Units That May Yet be Purchased Under the Plans or Programs(2)
April 1, 2019 - April 30, 2019	—	$	—	—	—
May 1, 2019 - May 31, 2019	1,268	$	16.59	—	—
June 1, 2019 - June 30, 2019	—	$	—	—	—

(1)

During the three months ended June 30, 2019, 1,268 common units were withheld to satisfy tax-withholding obligations arising in conjunction with the vesting of restricted units. The required withholding is calculated using the closing sales price per common unit reported by the New York Stock Exchange on the date prior to the applicable vesting date.

(2)

We did not have at any time during the quarter ended June 30, 2019, and currently do not have, a common unit repurchase program in place.

Table of Contents

Item 6. Exhibits

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

~~Table of Contents~~

~~EXHIBIT INDEX~~

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017)
3.2	—	~~First~~Third Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of ~~February 8, 2017~~September 23, 2018 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form ~~8‑K~~8-K filed ~~on February 14, 2017)~~September 25, 2018)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit ~~3.2~~3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (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)
10.1	—	Total Commitment Increase Agreement, dated as of May 23, 2019, between Frost Bank, Kimbell Royalty Partners, LP and Frost Bank, as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed May 28, 2019)
10.2	—	Additional Lender Agreement, dated as of May 23, 2019, between Independent Bank, Kimbell Royalty Partners, LP and Frost Bank, as administrative agent (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed May 28, 2019)
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

3337

Table of Contents

SIGNATURES

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


	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner

Date: ~~November 9, 2017~~August 8, 2019	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: ~~November 9, 2017~~August 8, 2019	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer

3438


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

Unit-based compensation		—		50,422

Net loss		—		(496,856)

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


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

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

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

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

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

Distributions to unitholders		—		(8,705,333)

Unit-based compensation		177,091		569,889

Net income		—		653,898

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


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