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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2019 OR

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

For the transition period from to

Commission file number: 001‑38005

Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)


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

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

(817) 945‑9700

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

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

Title of each class:

Trading symbol(s)

Name of exchange on which registered:

Common Units Representing Limited Partner Interests

KRP

New York Stock Exchange

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

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

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


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

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

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

As of August 2, 2019, the registrant had outstanding 23,494,135 common units 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 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	18
Item 3. Quantitative and Qualitative Disclosures About Market Risk	34
Item 4. Controls and Procedures	35


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	36
Item 1A. Risk Factors	36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 6. Exhibits	37
Signatures	38

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
	2019		2018
ASSETS
Current assets
Cash and cash equivalents	$	16,887,771	$	15,773,987
Oil, natural gas and NGL receivables		18,871,778		18,809,170
Commodity derivative assets		1,957,249		2,981,117
Accounts receivable and other current assets		376,121		50,551
Total current assets		38,092,919		37,614,825
Property and equipment, net		816,614		429,602
Oil and natural gas properties
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		2,749,255		3,178,627
Total assets	$	868,725,908	$	753,285,373

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	1,184,477	$	1,331,081
Other current liabilities		4,205,607		2,468,945
Total current liabilities		5,390,084		3,800,026
Operating lease liabilities		615,516		—
Commodity derivative liabilities		291,362		—
Long-term debt		87,309,544		87,309,544
Total liabilities		93,606,506		91,109,570
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.

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Revenue
Oil, natural gas and NGL revenues	$	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		1,924,943		805,396		3,521,337		1,621,397
Depreciation and depletion expense		12,311,443		3,431,594		22,592,451		7,887,302
Impairment of oil and natural gas properties		28,146,711		—		30,948,909		54,753,444
Marketing and other deductions		1,749,040		609,033		3,606,083		1,178,875
General and administrative expense		6,220,499		4,000,022		11,553,865		6,770,794
Total costs and expenses		50,352,636		8,846,045		72,222,645		72,211,812
Operating (loss) income		(18,416,035)		1,861,853		(22,338,835)		(50,612,576)
Other expense
Interest expense		1,441,651		483,558		2,864,214		833,600
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 (loss) income attributable to common units
Basic	$	(0.54)	$	0.08	$	(0.78)	$	(3.14)
Diluted	$	(0.54)	$	0.08	$	(0.78)	$	(3.14)
Weighted average number of common units outstanding
Basic		21,727,185		16,377,476		19,859,618		16,361,619
Diluted		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.

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)


	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.

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES
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		30,948,909		54,753,444
Amortization of right-of-use assets		22,578		—
Amortization of loan origination costs		518,149		31,250
Unit-based compensation		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		3,893,763		195,074
Accounts receivable and other current assets		(325,570)		10,032
Accounts payable		(949,806)		1,204,349
Other current liabilities		1,736,663		(519,935)
Operating lease liabilities		(27,006)		—
Net cash provided by operating activities		39,144,514		14,188,843
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(406,761)		(31,304)
Proceeds from sale of oil and natural gas properties		—		10,576,595
Deposits on oil and natural gas properties		—		(21,005,000)
Purchase of oil and natural gas properties		(998,550)		(17,585)
Net cash used in investing activities		(1,405,311)		(10,477,294)
CASH FLOWS FROM FINANCING ACTIVITIES
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		(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		—		19,000,000
Repayments on long-term debt		—		(6,870,596)
Payment of loan origination costs		(88,777)		—
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		1,113,784		2,709,137
CASH AND CASH EQUIVALENTS, beginning of period		15,773,987		5,625,495
CASH AND CASH EQUIVALENTS, end of period	$	16,887,771	$	8,334,632
Supplemental cash flow information:
Cash paid for interest	$	2,685,994	$	977,487
Non-cash investing and financing activities:
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.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10‑Q and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission. As a result, the accompanying unaudited interim condensed consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim condensed consolidated financial statements and related notes should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of the Partnership’s management, the unaudited interim condensed consolidated financial statements contain all adjustments necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP and all adjustments are of a normal recurring nature. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.

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

Segment Reporting

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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Restructuring, Tax Election and Related Transactions

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

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

For each Class B Unit issued, five cents has been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B Units are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A Preferred Units (as defined in Note 7—Long-Term Debt) but prior to distributions on the common units.

Following the effectiveness of the Tax Election and the completion of the related transactions, the Partnership’s royalty and minerals business continues to be conducted through the Operating Company, which is taxed as a partnership for federal and state income tax purposes. The Operating Company passes income to the noncontrolling interest and the Partnership, which is treated as a corporation for federal and state income tax purposes. As of 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 the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the six months ended June 30, 2019, other than those discussed below in Recently Adopted Accounting Pronouncements.

Reclassification of Prior Period Presentation

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

New Accounting Pronouncements

Recently Adopted Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016‑02, “Leases.” ASU 2016‑02 requires the recognition of right-of-use (“ROU”) assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year, with early adoption permitted. The Partnership adopted this update using the modified retrospective approach, effective January 1, 2019. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations for the three and six months ended June 30, 2019.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 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

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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 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)

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Joint Ventures

On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed $15.0 million. The Joint Venture will be managed by Springbok Operating Company, LLC. The purpose of the Joint Venture will be to make direct or indirect investments in royalty, mineral and overriding royalty interests and similar non-cost bearing interests in oil and gas properties, excluding leasehold or working interests. 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 Delaware Basin acreage for $10.6 million, which was recorded as a reduction in the full-cost pool, with no gain or loss recorded on the sale. At the time of the divestiture, the sales represented approximately 29 barrels of equivalent (“Boe”) per day of production, less than 0.8% of total production and 59 net royalty acres, approximately 0.08% of total net royalty acres.

NOTE 4—DERIVATIVES

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

As of 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)

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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.

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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 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 Partnership entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018, in connection with the Haymaker Acquisition, the Partnership entered into an amendment (the “Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement (the 2017 Credit Agreement as amended by the Credit Agreement Amendment, the “Amended Credit Agreement”), by and among the Partnership, certain subsidiaries of the Partnership, as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto.

The Credit Agreement Amendment amends the 2017 Credit Agreement to provide for, among other things, (i) the addition of the subsidiaries the Partnership acquired in the Haymaker Acquisition, as well as the Operating Company, as guarantors under the Amended Credit Agreement, (ii) limitations on the Partnership’s ability to incur certain debt or issue preferred equity, (iii) limitations on redemptions of the Series A Cumulative Convertible Preferred Units (“Series A Preferred Units”) and the ability of the Partnership and the restricted subsidiaries of the Partnership to make distributions and other restricted payments, in each case, unless certain conditions are satisfied, (iv) increased limitations on the Partnership’s ability to dispose of certain assets or encumber certain assets, (v) a decrease in the applicable margin under the 2017 Credit Agreement, which varies based upon the level of borrowing base usage, by 0.25% for each applicable

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level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 2.00% to 3.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement) and (vi) the addition of certain restrictions on the Partnership’s and the Operating Company’s ability to take certain actions or amend their organizational documents.

The Amended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The Amended Credit Agreement also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 4.0 to 1.0 and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The Amended Credit Agreement also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control.

The Credit Agreement Amendment increased commitments under the Amended Credit Agreement from $50.0 million to $200.0 million. Under the Amended Credit Agreement, availability under the secured revolving credit facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base under the Amended Credit Agreement was set at $200.0 million. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased to $500.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The borrowing base will be redetermined semiannually on May 1 and November 1 of each year based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the Partnership’s wholly owned subsidiaries. In 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 June 30, 2019, the Partnership’s outstanding balance was $87.3 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of June 30, 2019.

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

NOTE 8—PREFERRED UNITS

In July 2018, in connection with the closing of the Haymaker Acquisition, the Partnership completed the private placement of 110,000 Series A Preferred Units to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A Preferred Unit, resulting in gross proceeds to the Partnership of $110.0 million. 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

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(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.

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(Unaudited)

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

NOTE 10—EARNINGS (LOSS) PER UNIT

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Net (loss) income attributable to common units	$	(11,758,374)	$	1,378,295	$	(15,445,626)	$	(51,446,176)

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 (loss) income attributable to common units
Basic	$	(0.54)	$	0.08	$	(0.78)	$	(3.14)
Diluted	$	(0.54)	$	0.08	$	(0.78)	$	(3.14)

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 11—UNIT-BASED COMPENSATION

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

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(Unaudited)

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


		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2018	1,157,924	$	18.054	2.696 years
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 effective date of the Partnership’s change in income tax status, the Partnership was organized as a pass-through entity for income tax purposes. As a result, the Partnership’s partners were responsible for federal income taxes on their share of the Partnership’s taxable income with the exception of any entity-level income taxes such as the Texas Margins Tax. The Partnership recorded a provision for income taxes of $0.5 million for the three and six months ended June 30, 2019. The tax payment made by the Partnership for the three and six months ended June 30, 2019 was generated by a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker Acquisition.

NOTE 13—RELATED PARTY TRANSACTIONS

In connection with the IPO, the Partnership entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), Steward Royalties, LLC (“Steward Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”) pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders. During the three and six months ended June 30, 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 Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $131,714, $30,000, $81,918 and $124,576, respectively. During the six months ended June 30, 2019, the Partnership made payments to Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $263,428, $60,000, $163,836 and $249,152, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s LTIP.

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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 Form 10-Q, all such amounts have been collected from such employee by the Partnership.

NOTE 14—ADMINISTRATIVE SERVICES

Management Services Agreement

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

Transition Services Agreement

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

NOTE 15—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. The Partnership is currently assessing such a situation relating to certain non-producing acreage in its portfolio, the resolution of which is not expected to have a material impact on the Partnership’s condensed consolidated financial statements, and no amounts have been accrued as of June 30, 2019.

NOTE 16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to June 30, 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 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.

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(Unaudited)

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

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

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

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

References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner.

Cautionary Statement Regarding Forward‑Looking Statements

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

our ability to replace our reserves;

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

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

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

our ability to execute our business strategies;

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

the level of production on our properties;

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

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

general economic, business or industry conditions;

competition in the oil and natural gas industry;

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

title defects in the properties in which we acquire;

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

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

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

the availability of transportation facilities;

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

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

future operating results;

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

operating hazards faced by the operators of our properties;

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

certain factors discussed elsewhere in this Quarterly Report.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

Overview

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

As of June 30, 2019, we owned mineral and royalty interests in approximately 8.7 million gross acres and overriding royalty interests in approximately 4.3 million gross acres, with approximately 48% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of June 30, 2019, over 98% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 92,000 gross producing wells, including over 40,000 wells in the Permian Basin.

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

Transactions 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 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

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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 (as defined below), resulting in a total quarterly distribution of approximately $23,414 for the quarter ended June 30, 2019.

On July 26, 2019 the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.39 per common unit for the quarter ended June 30, 2019. The distribution will be paid on August 12, 2019 to common unitholders of record as of the close of business on 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. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (“EIA”).


	Six Months Ended June 30, 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 West Texas Intermediate posted price for crude oil was $56.85 per Bbl and the Henry Hub spot market price of natural gas was $2.23 per MMBtu.

The following table, as reported by the EIA, sets forth the average prices for oil and natural 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 exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The Baker Hughes United States Rotary Rig count decreased by 7.6% from 1,047 active rigs as of June 30, 2018 to 967 active rigs as of June 30, 2019.

We own mineral and royalty interests in 28 states. According to the Baker Hughes United States Rotary Rig count, rig activity in the 28 states in which we own mineral and royalty interests included 960 active rigs as of June 30, 2019 compared to 1,038 active rigs as of June 30, 2018.

The active rig count across our acreage as of June 30, 2019 remained steady at 89 active rigs compared to the active rigs at 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

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

The following table presents the breakdown of our operating income 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 oil and natural gas commodity derivative agreements with Frost Bank beginning January 1, 2018 which extends through June 2021 to establish, in advance, a price for the sale of a portion of the oil, natural gas and NGLs produced from our mineral and royalty interests.

Non‑GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution

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

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

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
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		1,441,651		483,558		2,864,214		833,600
Provision for income taxes		507,801		—		507,801		—
EBITDA		(6,104,592)		5,293,447		253,616		(42,725,274)
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
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		582,829		502,811		1,207,118		977,487
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	$	9,055,722	$	7,171,714	$	14,297,291	$	14,313,153

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	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

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

Restructuring, Tax Election and Related Transactions

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

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

For each Class B Unit issued, five cents has been paid to us as additional consideration (the “Class B Contribution”). Holders of the Class B Units are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A Preferred Units but prior to distributions on the common units.

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

Impairment of Oil and Natural Gas Properties

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

We recorded an impairment on our oil and natural gas properties of $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. We recorded an impairment on our oil and natural gas properties of $30.9 million and $54.8 million as a result of our quarterly full-cost ceiling analysis for the six months ended June 30, 2019 and 2018, respectively. As discussed in our Annual Report on Form 10-K for the year ended December 31, 2018, we do not intend to book proved undeveloped reserves going forward. As such, additional impairment charges could be recorded in connection with future acquisitions. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.

Credit Agreement

In connection with our IPO, on January 11, 2017, we entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018, in connection with the closing of the Haymaker Acquisition, we entered into an amendment (the “Credit Agreement Amendment”) to the 2017 Credit Agreement (the 2017 Credit Agreement as amended by the Credit Agreement Amendment, the “Amended Credit Agreement”), with certain of our subsidiaries, as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto.

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

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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 June 30, 2019, we had approximately $87.3 million in borrowings outstanding under our senior secured credit facility. For the three months ended June 30, 2019 and 2018, we incurred $1.4 million and $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.

Ongoing Acquisition Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three and 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 transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.

Management Services Agreements

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

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Transition Services Agreement

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

Results of Operations

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	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		1,924,943		805,396		3,521,337		1,621,397
Depreciation and depletion expense		12,311,443		3,431,594		22,592,451		7,887,302
Impairment of oil and natural gas properties		28,146,711		—		30,948,909		54,753,444
Marketing and other deductions		1,749,040		609,033		3,606,083		1,178,875
General and administrative expenses		6,220,499		4,000,022		11,553,865		6,770,794
Total costs and expenses		50,352,636		8,846,045		72,222,645		72,211,812
Operating (loss) income		(18,416,035)		1,861,853		(22,338,835)		(50,612,576)
Other expense
Interest expense		1,441,651		483,558		2,864,214		833,600
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)		268,963		108,201		495,564		218,087
Natural gas (Mcf)		4,030,160		999,019		7,366,883		1,983,385
Natural gas liquids (Bbls)		133,749		55,917		253,904		110,500
Combined volumes (Boe) (6:1)		1,074,405		330,621		1,977,282		659,151

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

Oil, Natural Gas and NGL Revenues

For the three months ended June 30, 2019, our oil, natural gas and NGL revenues were $27.9 million, an increase of $17.1 million from $10.8 million for the three months ended June 30, 2018. The increase in revenues was primarily attributable to the revenues associated with the Haymaker Acquisition, which represented approximately $10.1 million of the overall increase in oil, natural gas and NGL revenues, and to a lesser extent, the revenues associated with the Phillips Acquisition and Dropdown which contributed $5.4 million and $2.9 million, respectively, to the overall increase. Partially offsetting the increase in oil, natural gas and NGL revenues, was a decrease in the average prices we received for oil and NGL production.

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Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,074,405 Boe or 11,807 Boe/d, for the three months ended June 30, 2019, an increase of 743,784 Boe or 8,174 Boe/d, from 330,621 Boe or 3,633 Boe/d, for the three months ended June 30, 2018. The increase in production was primarily attributable to the Haymaker Acquisition, which represented 485,138 Boe or 5,331 Boe/d, and to a lesser extent, production associated with the Phillips Acquisition and Dropdown, which together accounted for 281,783 Boe or 3,097 Boe/d.

Our operators received an average of $57.55 per Bbl of oil, $2.44 per Mcf of natural gas and $19.55 per Bbl of NGL for the volumes sold during the three months ended June 30, 2019 and $63.45 per Bbl of oil, $2.59 per Mcf of natural gas and $25.03 per Bbl of NGL for the volumes sold during the three months ended June 30, 2018. The three months ended June 30, 2019 decreased 9.3% or $5.90 per Bbl of oil and 5.8% or $0.15 per Mcf of natural gas as compared to the three months ended June 30, 2018. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 12.0% or $8.19 per Bbl of 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 price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts.

Production and Ad Valorem Taxes

Production and ad valorem taxes increased significantly for the three months ended June 30, 2019 for a total of $1.9 million compared to $0.8 million for the three months ended June 30, 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 and, to the lesser extent, the Dropdown and Phillips Acquisition.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended June 30, 2019 was $12.3 million, an increase of $8.9 million from $3.4 million for the three months ended June 30, 2018. The increase in the depreciation and depletion expense was primarily attributable to the Haymaker Acquisition, the Dropdown and the Phillips Acquisition, which together added approximately $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 reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $11.45 for the three months ended June 30, 2019, an increase of $1.21 per barrel from the $10.24 average depletion rate per barrel for the three months ended June 30, 2018.

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 June 30, 2018.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post‑production expense. Marketing and other deductions for the three months ended June 30, 2019 were $1.7 million, an increase of $1.1 million from $0.6 million for the three months ended June 30, 2018. The increase in marketing and other deductions was primarily attributable to the Haymaker Acquisition, which represents $0.7 million of the overall increase, and to a lesser extent, the Dropdown and the Phillips Acquisition.

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General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2019 were $6.2 million, an increase of $2.2 million from $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 June 30, 2018. This increase was due to debt incurred to fund acquisitions in 2018, including the Haymaker Acquisition.

Provision for Income Taxes

We recorded a provision for income taxes of $0.5 million for the three 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.

Comparison of the Six Months Ended June 30, 2019 to the Six Months Ended June 30, 2018

Oil, Natural Gas and NGL Revenues

For the six months ended June 30, 2019, our oil, natural gas and NGL revenues were $50.7 million, an increase of $29.0 million from $21.7 million for the six months ended June 30, 2018. The increase in revenues was primarily attributable to the revenues associated with the Haymaker Acquisition, which represented approximately $20.1 million of the overall increase in oil, natural gas and NGL revenues, and to a lesser extent, the revenues associated with the Phillips Acquisition and Dropdown, which contributed $10.8 million and $5.9 million, respectively, to the overall increase. Partially offsetting the increase in oil, natural gas and NGL revenues, was a decrease in the average prices we received for oil and NGL production.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,977,282 Boe or 10,924 Boe/d, for the six months ended June 30, 2019, an increase of 1,318,131 Boe or 7,282 Boe/d, from 659,151 Boe or 3,642 Boe/d, for the six months ended June 30, 2018. The increase in production was primarily attributable to the Haymaker Acquisition, which represented 948,043 Boe or 5,238 Boe/d, and to a lesser extent, production associated with the Phillips Acquisition and Dropdown, which together accounted for 570,064 Boe or 3,150 Boe/d.

Our operators received an average of $54.51 per Bbl of oil, $2.55 per Mcf of natural gas and $19.62 per Bbl of NGL for the volumes sold during the six months ended June 30, 2019 and $62.20 per Bbl of oil, $2.64 per Mcf of natural gas and $25.85 per Bbl of NGL for the volumes sold during the six months ended June 30, 2018. The six months ended June 30, 2019 decreased 12.4% or $7.69 per Bbl of oil and 3.4% or $0.09 per Mcf of natural gas compared to the six months ended June 30, 2018. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 12.4% or $8.16 per Bbl of oil and 7.4% or $0.22 per Mcf of natural gas for the comparable periods.

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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

Production and ad valorem taxes increased significantly for the six months ended June 30, 2019 for a total of $3.5 million compared to $1.6 million for the three months ended June 30, 2018. The increase was primarily attributable to the Haymaker Acquisition, which accounted for $0.9 million of the increase in production and ad valorem taxes and, to the lesser extent, the Dropdown and Phillips Acquisition.

Depreciation and Depletion Expense

Depreciation and depletion expense for the six months ended June 30, 2019 was $22.6 million, an increase of $14.7 million from $7.9 million for the six months ended June 30, 2018. The increase in the depreciation and depletion expense was primarily attributable to the Haymaker Acquisition, the Dropdown and the Phillips Acquisition, which together added approximately $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 reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $11.42 for the six months ended June 30, 2019, a decrease of $0.41 per barrel from the $11.83 average depletion rate per barrel for the six months ended June 30, 2018. The decrease was primarily attributable to the $54.8 million of impairment recorded on our oil and natural gas properties during the six months ended June 30, 2018.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

We recorded an impairment expense on our 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 our quarterly full cost ceiling analysis.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post‑production expense. Marketing and other deductions for the six months ended June 30, 2019 were $3.6 million, an increase of $2.4 million from $1.2 million for the six months ended June 30, 2018. The increase in marketing and other deductions was primarily attributable to the Haymaker Acquisition, which represents $1.6 million of the overall increase, and to a lesser extent, the Dropdown and the Phillips Acquisition.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2019 were $11.6 million, an increase of $4.8 million from $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 cash general and administrative expenses resulting from the Haymaker Acquisition, Dropdown and Phillips Acquisition.

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Interest Expense

Interest expense for the six months ended June 30, 2019 was $2.9 million as compared to interest expense of $0.8 million for the six months ended June 30, 2018. This increase was due to debt incurred to fund acquisitions in 2018, including the Haymaker Acquisition.

Provision for Income Taxes

We recorded a provision for income taxes of $0.5 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. On July 12, 2018, we entered into an amendment to the 2017 Credit Agreement, increasing commitments under the secured revolving credit facility from $50.0 million to $200.0 million, with an accordion feature permitting aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders), to be used for general partnership purposes, including working capital and acquisitions, among other things. In connection with the redetermination of the borrowing base in May 2019, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million. As of August 2, 2019, we had an outstanding balance of $87.3 million under our secured revolving credit facility.

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. Available cash is defined in the limited liability company agreement of the Operating Company and our partnership agreement. We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate. We do not currently intend to maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we completed the Haymaker Acquisition by providing equity consideration for the transaction in the form of 10,000,000 common units and funding the cash consideration of the transaction through the net proceeds from the 2018 preferred offering and borrowings of $124.0 million under the Amended Credit Agreement, while the Dropdown was financed by providing equity consideration for the transaction in the form of 6,500,000 OpCo Common Units and an equal number of Class B Units, and the Phillips Acquisition was financed by providing equity consideration for the transaction in the form of 9,400,000 OpCo Common Units and an equal number of Class B Units. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well.

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Because the limited liability company agreement of the Operating Company and our partnership agreement each require the Operating Company and us to distribute an amount equal to all available cash generated by each respective entity each quarter, holders of OpCo Common Units and our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and NGLs, changes to working capital or capital expenditures, (iii) tax and certain contractual obligations and (iv) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of quarterly distributions may be significant and could result in no distribution being made for any particular quarter. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve a material amount of cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

On 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 $0.39 per common unit for the quarter ended June 30, 2019. The distribution will be paid on August 12, 2019 to common unitholders and OpCo common unitholders of record as of the close of business on August 5, 2019.

Cash Flows

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


	Six Months Ended June 30,
	2019		2018
Cash Flow Data:
Cash flows provided by operating activities	$	39,144,514	$	14,188,843
Cash flows used in investing activities		(1,405,311)		(10,477,294)
Cash flows used in financing activities		(36,625,419)		(1,002,412)
Net increase in cash	$	1,113,784	$	2,709,137

Operating Activities

Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and the change in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the six months ended June 30, 2019 were $39.1 million, an increase of $24.9 million compared to $14.2 million for the six months ended June 30, 2018. The increase in cash flows provided by operating activities was primarily attributable to the Haymaker Acquisition and Dropdown in the third and fourth quarters of 2018, respectively, and to the Phillips Acquisition in the first quarter of 2019.

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Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2019 decreased by $9.1 million compared to the six months ended June 30, 2018. For the six months ended June 30, 2019, we used $1.0 million to fund the 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 the sale of oil and natural gas properties.

Financing Activities

Cash flows used in financing activities were $36.6 million for the six months ended June 30, 2019, an increase of $35.6 million compared to $1.0 million for the six months ended June 30, 2018. Cash flows used in financing activities for the six months ended June 30, 2019 consists of $36.3 million of distributions paid to holders of common units and OpCo common units, Series A Preferred Units and Class B Units and $0.7 million of issuance costs paid on Series A Preferred Units, partially offset by $0.5 million in contributions from our Class B unitholders. Cash flows used in financing activities for the six months ended June 30, 2018 consists of $13.1 million of distributions paid to common unitholders and $6.9 million of repayments on our secured revolving credit facility, offset by $19.0 million of additional borrowings under our secured revolving credit facility.

Capital Expenditures

During the six months ended June 30, 2019, we paid approximately $1.0 million in connection with the Phillips Acquisition. During the six months ended June 30, 2018, we paid a $21.0 million deposit in connection with the Haymaker Acquisition.

Indebtedness

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

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

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

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

New and Revised Financial Accounting Standards

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

Critical Accounting Policies and Related Estimates

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

Contractual Obligations and Off‑Balance Sheet Arrangements

There have been no 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. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparty to the contracts is an unrelated third party.

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

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

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

Counterparty and Customer Credit Risk

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

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

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Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of June 30, 2019, we had total borrowings outstanding under our secured revolving credit facility of $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 $0.9 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the risks under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018. There have been no material changes to the risk factors previously discussed in Item 1A. Risk Factors in the Partnership’s 2018 Form 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

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

On 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.

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Item 6. Exhibits

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017)
3.2	—	Third Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017)
3.4	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Form 8‑K filed on February 14, 2017)
3.5	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)
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

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SIGNATURES

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


	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner

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


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