Kimbell Royalty Partners, LP - Quarter Report: 2018 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑Q


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

For the quarterly period ended September 30, 2018 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)

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

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

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


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

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

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

As of November 2, 2018, the registrant had outstanding 17,336,204 common units representing limited partner interests and 12,953,258 Class B units representing limited partner units.

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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	36
Item 4. Controls and Procedures	37


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 6. Exhibits	38
Signatures	40

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PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30,		December 31,
	2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	16,527,967	$	5,625,495
Oil, natural gas and NGL receivables		17,497,528		6,792,837
Accounts receivable and other current assets		426,766		236,673
Total current assets		34,452,261		12,655,005
Property and equipment, net		452,634		165,232
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($288,334,110 and $0 excluded from depletion at September 30, 2018 and December 31, 2017, respectively)		731,084,956		297,609,797
Less: accumulated depreciation, depletion, accretion and impairment		(85,533,043)		(15,394,238)
Total oil and natural gas properties		645,551,913		282,215,559
Loan origination costs, net		3,436,353		255,208
Total assets	$	683,893,161	$	295,291,004

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	1,502,054	$	316,486
Other current liabilities		3,994,853		1,746,662
Commodity derivative liabilities		769,698		183,957
Total current liabilities		6,266,605		2,247,105
Commodity derivative liabilities		3,044,594		134,872
Deferred tax liability		1,475,648		—
Long-term debt		148,309,544		30,843,593
Total liabilities		159,096,391		33,225,570
Commitments and contingencies (Note 15)
Mezzanine equity:
Series A preferred units (110,000 units issued and outstanding as of September 30, 2018 and 0 units issued and outstanding as of December 31, 2017)		67,904,422		—
Unitholders' equity:
Common units (13,886,204 units issued and outstanding as of September 30, 2018 and 16,509,799 units issued and outstanding as of December 31, 2017)		246,793,808		262,065,434
Class B units (12,953,258 units issued and outstanding as of September 30, 2018 and 0 units issued and outstanding as of December 31, 2017)		647,663		—
Total unitholders' equity		247,441,471		262,065,434
Noncontrolling interest		209,450,877		—
Total equity		456,892,348		262,065,434
Total liabilities, mezzanine equity and unitholders' equity	$	683,893,161	$	295,291,004

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)


	Partnership								Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,
	2018		2017		2018		2017		2017
Revenue
Oil, natural gas and NGL revenues	$	21,085,377	$	8,174,195	$	42,741,233	$	20,479,537	$	318,310
Lease bonus and other income		358,215		177,204		1,124,949		177,204		—
Loss on commodity derivative instruments		(3,035,636)		—		(3,858,990)		—		—
Total revenues		18,407,956		8,351,399		40,007,192		20,656,741		318,310
Costs and expenses
Production and ad valorem taxes		1,410,335		778,733		3,031,732		1,602,520		19,651
Depreciation, depletion and accretion expense		7,607,137		4,488,915		15,494,439		11,156,292		113,639
Impairment of oil and natural gas properties		—		—		54,753,444		—		—
Marketing and other deductions		1,689,780		424,702		2,868,655		1,068,509		110,534
General and administrative expense		4,879,497		2,314,718		11,650,291		5,707,093		532,035
Total costs and expenses		15,586,749		8,007,068		87,798,561		19,534,414		775,859
Operating income (loss)		2,821,207		344,331		(47,791,369)		1,122,327		(457,549)
Other expense
Interest expense		1,843,483		225,302		2,677,083		468,429		39,307
Net income (loss) before income taxes		977,724		119,029		(50,468,452)		653,898		(496,856)
Provision for income taxes		1,977,116		—		1,977,116		—		—
Net (loss) income before Series A preferred unit distribution and accretion		(999,392)		119,029		(52,445,568)		653,898		(496,856)
Distribution and accretion on Series A preferred units		(2,840,456)		—		(2,840,456)		—		—
Net (loss) income		(3,839,848)		119,029		(55,286,024)		653,898		(496,856)
Net loss attributable to noncontrolling interests		(141,003)		—		(141,003)		—		—
Net (loss) income attributable to Kimbell Royalty Partners LP		(3,698,845)		119,029		(55,145,021)		653,898		(496,856)
Distribution on Class B units		(12,953)		—		(12,953)		—		—
Net (loss) income attributable to common units	$	(3,711,798)	$	119,029	$	(55,157,974)	$	653,898	$	(496,856)

Net (loss) income attributable to common units
Basic	$	(0.15)	$	0.01	$	(2.91)	$	0.04	$	(0.82)
Diluted	$	(0.15)	$	0.01	$	(2.91)	$	0.04	$	(0.82)
Weighted average number of common units outstanding
Basic		24,079,289		16,337,985		18,962,446		16,334,774		604,137
Diluted		24,079,289		16,503,664		18,962,446		16,434,385		604,137

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)


									Noncontrolling
	Common Units		Amount		Class B Units		Amount		Interest		Total
Balance at December 31, 2017		16,509,799	$	262,065,434		—	$	—	$	—	$	262,065,434
Common units issued for acquisition		10,000,000		235,400,000		—		—		—		235,400,000
Recapitalization related to tax conversion		(12,953,258)		(209,591,880)		12,953,258		647,663		209,591,880		647,663
Unit-based compensation		—		2,143,047		—		—		—		2,143,047
Distributions to unitholders		—		(24,672,785)		—		—		—		(24,672,785)
Restricted units granted, net of forfeitures		329,663		—		—		—		—		—
Issuance of Series A preferred units		—		36,607,966		—		—		—		36,607,966
Distribution and accretion on Series A preferred units		—		(2,840,456)		—		—		—		(2,840,456)
Distribution on Class B units		—		(12,953)		—		—		—		(12,953)
Net loss before Series A preferred unit distribution and accretion		—		(52,304,565)		—		—		(141,003)		(52,445,568)
Balance at September 30, 2018		13,886,204	$	246,793,808		12,953,258	$	647,663	$	209,450,877	$	456,892,348

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

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KIMBELL ROYALTY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Partnership				Predecessor
	Nine Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,
	2018		2017		2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income before Series A preferred unit distribution and accretion	$	(52,445,568)	$	653,898	$	(496,856)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Provision for deferred income taxes		1,475,648		—		—
Depreciation, depletion and accretion expense		15,494,439		11,156,292		113,639
Impairment of oil and natural gas properties		54,753,444		—		—
Amortization of loan origination costs		208,276		41,667		4,241
Amortization of tenant improvement allowance		—		—		(2,864)
Unit-based compensation		2,143,047		569,889		50,422
Loss on commodity derivative instruments		3,495,463		—		—
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(8,781,555)		(496,886)		14,551
Accounts receivable and other current assets		(190,093)		(258,785)		333,056
Accounts payable		1,172,615		152,569		247,972
Other current liabilities		1,266,354		2,146,834		(77,442)
Net cash provided by operating activities		18,592,070		13,965,478		186,719
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(396,480)		(57,592)		—
Proceeds from sale of oil and natural gas properties		10,576,595		—		—
Deposits on oil and natural gas properties		—		(3,949,000)		—
Purchase of oil and natural gas properties		(210,574,890)		(113,183,664)		(523)
Net cash used in investing activities		(200,394,775)		(117,190,256)		(523)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of Series A preferred units, net of issuance costs		103,359,603		—		—
Contributions from Class B unitholders		647,663		—		—
Proceeds from initial public offering		—		96,255,000		—
Distributions to unitholders		(24,672,785)		(8,705,333)		—
Distributions on Series A preferred units		(705,834)		—		—
Borrowings on long-term debt		124,336,547		22,214,090		—
Repayments on long-term debt		(6,870,596)		—		—
Payment of loan origination costs		(3,389,421)		(312,500)		—
Net cash provided by financing activities		192,705,177		109,451,257		—
NET INCREASE IN CASH AND CASH EQUIVALENTS		10,902,472		6,226,479		186,196
CASH AND CASH EQUIVALENTS, beginning of period		5,625,495		—		505,880
CASH AND CASH EQUIVALENTS, end of period	$	16,527,967	$	6,226,479	$	692,076
Supplemental cash flow information:
Cash paid for interest	$	2,220,885	$	276,246	$	34,505
Cash paid for taxes	$	—	$	—	$	5,355
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties	$	235,400,000	$	—	$	—
Distribution to Class B unitholders in accounts payable	$	12,953	$	—	$	—
Distribution to Series A preferred unitholders in accounts payable	$	981,837	$	—	$	—
Non-cash deemed distribution to Series A preferred units	$	1,152,785		—	$	—
Capital expenditures through issuance of common units	$	—	$	176,404,698	$	—

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,” “we,” “our,” “us” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “the Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership. References to “the Predecessor,” or “Rivercrest” refer to Rivercrest Royalties, LLC, the predecessor for accounting and financial reporting purposes. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner.

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing of the IPO. As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of the Predecessor and does not include the results of the Partnership as a whole. The mineral and royalty interests underlying the oil, natural gas and natural gas liquids (“NGL”) production revenues of the Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

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

Registration Rights Agreement

On July 12, 2018, in connection with the Haymaker Acquisition and pursuant to the terms of the Preferred Purchase Agreement (as defined in Note 8 – Preferred Units), the Partnership entered into a registration rights agreement (the “Registration Rights Agreement”) with Haymaker Minerals, the Haymaker Resources Holders and the Purchasers (as defined in Note 8 – Preferred Units), pursuant to which, among other things, the Partnership agreed to (i) prepare, file with the United States Securities and Exchange Commission (“SEC”) and use its reasonable best efforts to cause to become effective within 160 days of the execution of the Registration Rights Agreement, a shelf registration statement (the “Shelf Registration Statement”) with respect to the resale of the common units issued to Haymaker Minerals and the Haymaker Resources Holders and issuable upon conversion of the Series A Cumulative Convertible Preferred Units (the “Series A Preferred Units”) of the Partnership (all such common units being “Registrable Securities”) that would permit some or all of the Registrable Securities to be resold in registered transactions, (ii) use its reasonable best efforts to maintain the effectiveness of the Shelf Registration Statement while Haymaker Minerals, the Haymaker Resources Holders, the

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Purchasers and each of their transferees that hold Registrable Securities are in possession of Registrable Securities and (iii) under certain circumstances, initiate underwritten offerings for the Registrable Securities.

If a Shelf Registration Statement is not effective prior to the day the Series A Preferred Units are convertible into common units pursuant to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Second Amended and Restated Partnership Agreement”), then Haymaker Minerals, the Haymaker Resources Holders and the Purchasers, as applicable, will be entitled to certain liquidated damages as set forth in the Registration Rights Agreement.

In addition, the Registration Rights Agreement permits Haymaker Minerals, the Haymaker Resources Holders and the Purchasers to request to sell any or all of their Registrable Securities in an underwritten offering that is registered pursuant to a Shelf Registration Statement, subject to certain exceptions, including, among other things, that the gross proceeds from the sale are reasonably expected to exceed $50.0 million in the aggregate.

On July 30, 2018, the Partnership filed a registration statement on Form S-3 (the “Form S-3”) to satisfy, in part, certain rights and obligations under the Registration Rights Agreement. The Form S-3, effective on September 21, 2018, registered (i) the offer and sale by the Partnership of up to an aggregate of $200.0 million of its securities and (ii) the offer and resale of up to an aggregate of 15,945,946 of the Partnership’s common units by the holders of Registrable Securities named therein.

Recapitalization Agreement

On July 24, 2018, the Partnership entered into a Recapitalization Agreement (the "Recapitalization Agreement"), by and among Haymaker Minerals and Haymaker Resources Holders, Haymaker Resources, LP, the Kimbell Art Foundation (the "Foundation"), the Partnership, the General Partner, and Kimbell Royalty Operating, LLC (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 Preferred Units and (b) the 10,000,000 and 2,953,258 common units held by Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC (together, the “Haymaker Holders”) and the 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.

Tax Status Election and Restructuring

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”). On September 24, 2018, the Tax Election became effective. In preparation for making this election, on September 23, 2018, the Partnership (i) amended and restated its Second Amended and Restated Limited Partnership Agreement, (ii) amended and restated the Limited Liability Company Agreement of the Operating Company (iii) entered into an exchange agreement with the Haymaker Holders, the Foundation, the General Partner and the Operating Company.

Simultaneously with the effectiveness of these agreements, the transactions described in the Recapitalization Agreement were consummated.

Pursuant to the terms of the Recapitalization Agreement, the Haymaker Holders and the Foundation each paid five cents per Class B Unit to the Partnership as additional consideration with respect to the Class B Units (the “Class B Contribution”). The Haymaker Holders and the Foundation, as 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.

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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.

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and with the instructions to Form 10‑Q and pursuant to the rules and regulations of the SEC. As a result, the accompanying unaudited interim condensed consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim condensed consolidated financial statements and related notes should be read in conjunction with the Partnership’s and the Predecessor’s financial statements for the years ended December 31, 2017 and 2016, which are included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017. In the opinion of the Partnership’s management, the unaudited interim condensed consolidated financial statements contain all adjustments of a normal recurring nature necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP. 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.

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 Partnership’s 2017 Form 10-K as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the nine months ended September 30, 2018.

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 May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue From Contracts with Customers (Topic 606)”, an ASU on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.

On January 1, 2018 the Partnership adopted ASU 2014-09 using the full retrospective method. The Partnership completed its review of a representative sample of revenue contracts covering its material revenue streams and determined that there is no impact to its consolidated financial statements, results of operations or liquidity. When comparing the Partnership’s historical revenue recognition to the newly applied revenue recognition under ASC 606, there was no change to the amount or timing of revenue recognized. Therefore, no quantitative adjustment was required to be made to the prior periods presented in the unaudited interim condensed consolidated financial statements after the adoption of ASC 606. Upon adoption, the Partnership did not alter its existing information technology and internal controls outside of the contract review processes in order to identify impacts of future revenue contracts the Partnership may enter into.

Accounting Policy – Revenues from royalty properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received one to four months after the production month, the Partnership accrues for revenue earned but not received by estimating production volumes and product prices.

Revenues from lease bonus are recorded upon receipt. The lease bonus is separate from the lease itself and is recognized as revenue to the Partnership upon receipt of payment.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations—Clarifying the Definition of a Business.” This update applies to all entities that must determine whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The update requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the transaction should not be accounted for as a business. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations.

In June 2018, the FASB ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting. ASU 2018-07 simplifies the accounting for share-based payments to nonemployees by aligning it with the accounting for share-based payments to employees, with certain exceptions. The amendments in this ASU are effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year, with early adoption permitted. The Partnership early adopted ASU 2018-07 effective January 1, 2018. This standard substantially aligned the accounting for share based payments to employees and nonemployees. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations.

Accounting Pronouncements Not Yet Adopted

In February 2016, the FASB issued ASU 2016‑02, “Leases”. ASU 2016‑02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Partnership believes the adoption of this update will not have a material impact on its financial position, results of operations or liquidity.

In July 2018, the FASB issued 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. 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. The Partnership is still evaluating the impact of this standard.

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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 will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

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 will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

NOTE 3—ACQUISITIONS AND DIVESTITURES

2018 Activity

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 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.

On July 12, 2018, the Partnership completed the Haymaker Acquisition in a transaction valued at approximately $444.0 million. The purchase price for the Haymaker Acquisition was comprised of (i) cash consideration of approximately $216.8 million, which was reduced by approximately $6.4 million of cash acquired and by approximately $9.3 million for net cash received or receivable by the Partnership for oil and natural gas production revenue occurring prior to the closing date of July 12, 2018 and increased by approximately $7.5 million in capitalized transaction costs for a net amount of approximately $208.6 million (the “Cash Consideration”) and (ii) 10,000,000 common units of the Partnership, valued at approximately $235.4 million based on the closing price of $23.54 on July 12, 2018. The Partnership funded the Cash Consideration with borrowings under the Amended Credit Agreement (as defined in Note 7 – Long Term Debt) and net proceeds from the Preferred Unit Transaction (as defined in Note 8 – Preferred Units). The assets acquired in the Haymaker Acquisition, consist of approximately 5.4 million gross acres and 43,000 net royalty acres.

The following unaudited pro forma results of operations reflect our results as if the Haymaker Acquisition had occurred on January 1, 2017. In our opinion, all significant adjustments necessary to reflect the effects of the acquisitions have been made. Pro forma data may not be indicative of the results that would have been obtained had these events occurred at the beginning of the periods presented, nor is it intended to be a projection of future results.


	Three Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,		Nine Months Ended September 30,
	2018		2017		2018		2017
Total revenues	$	19,808,076	$	18,032,497	$	64,235,908	$	59,889,582
Net loss attributable to common units	$	(1,236,577)	$	(2,396,601)	$	(24,263,761)	$	(5,428,729)

Net loss attributable to common units
Basic	$	(0.09)	$	(0.17)	$	(1.75)	$	(0.39)
Diluted	$	(0.09)	$	(0.17)	$	(1.75)	$	(0.39)

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2017 Activity

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

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.

At September 30, 2018, 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. Prior to the Haymaker Acquisition, this amount constituted approximately 10% of daily oil and natural gas production. Following the closing of the Haymaker Acquisition, the Partnership hedged daily oil and natural gas production of approximately 30% of its post-acquisition 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 September 30,		Nine Months Ended September 30,
	2018		2018
Beginning fair value of commodity derivative instruments	$	(1,000,359)	$	(318,829)
Loss on commodity derivative instruments		(3,035,636)		(3,858,990)
Net cash paid on settlements of derivative instruments		221,703		363,527
Ending fair value of commodity derivative instruments	$	(3,814,292)	$	(3,814,292)

At September 30, 2018, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps


	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High
September 2018 - December 2018	74,911	$	64.75	$	56.00	$	68.60
January 2019 - December 2019	224,110	$	61.47	$	53.07	$	63.47
January 2020 - June 2020	111,748	$	60.45	$	56.03	$	61.43

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Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
October 2018 - December 2018	972,716	$	2.83	$	2.71	$	2.84
January 2019 - December 2019	3,859,145	$	2.74	$	2.74	$	2.76
January 2020 - June 2020	1,924,286	$	2.70	$	2.51	$	2.94

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 at September 30, 2018 and December 31, 2017. 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 nine months ended September 30, 2018 and 2017.

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:


	September 30,		December 31,
	2018		2017
Oil and natural gas properties
Proved properties	$	442,750,846	$	297,609,797
Unevaluated properties		288,334,110		—
Less: accumulated depreciation, depletion and impairment		(85,533,043)		(15,394,238)
Total oil and natural gas properties	$	645,551,913	$	282,215,559

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.

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No impairment expense was recorded for the three months ended September 30, 2018. The Partnership recorded an impairment on its oil and natural gas properties of $54.8 million during the nine months ended September 30, 2018, as a result of our quarterly full cost ceiling analysis during the three months ended March 31, 2018. No impairment expense was recorded for the period from February 8, 2017 to September 30, 2017 or for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”).

NOTE 7—LONG-TERM DEBT

Existing Credit Agreement

In connection with its IPO, the Partnership entered into a $50.0 million secured revolving credit facility that is secured by substantially all of its assets and the assets of its wholly owned subsidiaries. Availability under the secured revolving credit facility will continue to equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will continue to be re-determined semi-annually on February 1 and August 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 its wholly owned subsidiaries. The secured revolving credit facility matures on February 8, 2022.

The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility 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 secured revolving credit facility also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control.

Amendment to the Existing Credit Agreement

On July 12, 2018, in connection with the Haymaker Acquisition, the Partnership entered into an amendment (the “Credit Agreement Amendment”) to the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (the “Existing Credit Agreement” and, the Existing 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 increased commitments under the Amended Credit Agreement from $50.0 million to $200.0 million. Under the Amended Credit Agreement, availability under the 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 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 first redetermination date will be February 1, 2019.

The Credit Agreement Amendment amends the Existing 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 (other than 110,000 Series A Preferred Units representing limited partner interests in the Partnership, (iii) limitations on redemptions of the 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 Existing 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

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addition of certain restrictions on the Partnership’s and the Operating Company’s ability to take certain actions or amend their organizational documents.

During the nine months ended September 30, 2018, the Partnership borrowed an additional $124.4 million under the secured revolving credit facility and repaid $6.9 million of the total outstanding borrowings. As of September 30, 2018, the Partnership’s outstanding balance was $148.3 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of September 30, 2018.

At September 30, 2018, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.50% or Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.50%. For the nine months ended September 30, 2018, the weighted average interest rate on the Partnership’s outstanding borrowings was 4.63%.

NOTE 8—PREFERRED UNITS

Preferred Purchase Agreement

On May 28, 2018, the Partnership entered into a Series A Preferred Unit Purchase Agreement (the “Preferred Purchase Agreement”) with certain affiliates of Apollo Capital Management, L.P. (collectively, the “Purchasers”) to issue and sell the Series A Preferred Units. The Series A Preferred Units were offered in a private placement (the “Preferred Unit Transaction”). The Preferred Unit Transaction closed on July 12, 2018, with the Series A Preferred Units being issued and sold for a cash purchase price of $1,000 per Series A Preferred Unit, resulting in gross proceeds to the Partnership of $110.0 million.

The Series A Preferred Units pay a 7% distribution rate and are convertible by the 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 at a redemption price that is the greater of 1.2 times the invested capital.

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


		Series A
		Preferred Units
Balance at December 31, 2017		—
Series A preferred units issued		110,000
Balance at September 30, 2018		110,000

In August 2018, the Partnership paid a quarterly cash distribution on the Series A Preferred Units of $0.7 million for the quarter ended September 30, 2018.

Board Rights Agreement

On July 12, 2018, pursuant to the Preferred Purchase Agreement, the Partnership, the General Partner, and Kimbell GP Holdings, LLC entered into a Board Representation and Observation Agreement (the “Board Rights Agreement”) with the Purchasers. Pursuant to the Board Rights Agreement, the Partnership granted holders of the Series A Preferred Units board observer rights beginning three years after the closing of the Preferred Unit Transaction, and board appointment rights beginning four years after the closing of the Preferred Unit Transaction and in the case of events of default with respect to the Series A Preferred Units.

NOTE 9—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has limited partner units. At September 30, 2018, the Partnership had a total of 13,886,204 common units issued and outstanding and 12,953,258 Class B Units outstanding.

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


		Common Units
Balance at December 31, 2017		16,509,799
Common units issued under the LTIP (1)		329,663
Common units issued for acquisition		10,000,000
Unit exchange related to tax conversion		(12,953,258)
Balance at September 30, 2018		13,886,204

(1)

Includes 326,654 restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on January 29, 2018, 4,478 of restricted units granted to a new director under the LTIP on May 9, 2018, and the forfeiture of 1,469 units.

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

Q1 2017 (1)	$	0.23	May 2, 2017	May 8, 2017	May 15, 2017
Q2 2017	$	0.30	July 28, 2017	August 7, 2017	August 14, 2017
Q3 2017	$	0.31	October 27, 2017	November 6, 2017	November 13, 2017

(1)

The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

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


		Class B Units
Balance at December 31, 2017		—
Unit exchange related to tax conversion		12,953,258
Balance at September 30, 2018		12,953,258

Pursuant to the terms of the Recapitalization Agreement, the Haymaker Holders and the Foundation, as 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.

The Class B Units and OpCo Common Units are exchangeable together into an equal number of common units of the Partnership. See Recapitalization Agreement in Note 1 for further detail.

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 common units granted under the Partnership’s LTIP for its employees, directors and consultants and unvested options granted under the Predecessor’s long-term incentive plan as described in Note 10—Unit-Based Compensation. The calculation of diluted net loss per share for the three and nine months ended September 30, 2018 excludes the conversion of the Class B Units to common units and 437,641 of non-vested shares of restricted stock units issuable upon vesting, because their inclusion in the calculation would be anti-dilutive. For the Predecessor 2017 Period, the effect of the 110,000 options issued under the Predecessor’s long-term incentive plan were

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anti-dilutive. Therefore, the options issued under the Predecessor’s long-term incentive plan were not included in the diluted EPU calculation on the accompanying unaudited condensed consolidated statement of operations for this period.

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


	Partnership								Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,
	2018		2017		2018		2017		2017
Net (loss) income attributable to common units	$	(3,711,798)	$	119,029	$	(55,157,974)	$	653,898	$	(496,856)

Net (loss) income attributable to common units
Basic	$	(0.15)	$	0.01	$	(2.91)	$	0.04	$	(0.82)
Diluted	$	(0.15)	$	0.01	$	(2.91)	$	0.04	$	(0.82)
Weighted average number of common units outstanding
Basic		24,079,289		16,337,985		18,962,446		16,334,774		604,137
Diluted		24,079,289		16,503,664		18,962,446		16,434,385		604,137

NOTE 11—UNIT-BASED COMPENSATION

On September 23, 2018, the General Partner entered into the First Amendment to the LTIP (the “LTIP Amendment), whereas the LTIP Amendment 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 our 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. After the adoption of ASU 2018-07, compensation expense for consultants will be treated in the same manner as that of the employees and directors.

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


		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2017	167,571	$	18.655	1.364 years
Granted - service condition employees	327,306		19.080	-
Granted - service condition consultants	3,826		16.260	-
Forfeited	(1,469)		(16.260)	-
Vested	(59,593)		(18.420)	-
Unvested at September 30, 2018	437,641	$	18.878	1.28 years

Prior to the IPO, the Predecessor had a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options as compensation for services performed for the Predecessor. For the Predecessor

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2017 Period, total compensation expense for awards under the Predecessor’s long-term incentive plan was $0.05 million and is included general and administrative expenses in the accompanying unaudited condensed consolidated statement of operations. In connection with the transactions that were completed at the closing of the Partnership’s IPO, the outstanding options to purchase membership units under the Predecessor’s long-term incentive plan expired and were not converted to units in the Partnership.

NOTE 12—INCOME TAXES

As discussed further in Note 1, on May 28, 2018, the Partnership announced that the Board of Directors had 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 for the period ended September 30, 2018 is based on the estimated annual effective tax rate plus discrete items.

The Partnership’s effective income tax rate was (3.9)% for the nine months ended September 30, 2018. Total income tax expense for the nine months ended September 30, 2018 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the impact of discrete items such as $1.5 million of tax expense recognized as a result of the Partnership’s change in tax status and tax expense of $0.5 million recognized in connection with the Preferred Purchase Agreement.

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. Tax expense recorded by the Partnership from September 24, 2018 to September 30, 2018 was insignificant.

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 service agreements with Steward Royalties, LLC (“Steward Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”) pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective service agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective service agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders. During the three months ended September 30, 2018, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $32,500, $131,714, $30,000, $89,209 and $130,495, respectively. During the nine months ended September 30, 2018, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $97,500, $395,141, $90,000, $267,628 and $391,486, respectively.

During the Predecessor 2017 Period, the Predecessor had certain related party receivables and payables; however, such amounts were de minimis.

NOTE 14—ADMINISTRATIVE SERVICES

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 12―Related Party Transactions.

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(Unaudited)

Transition Services Agreement

On July 12, 2018, pursuant to the Haymaker Acquisition, the Partnership entered into a Transition Services Agreement (the “Transition Services Agreement”) with Haymaker Services, LLC (“Haymaker Services”). Pursuant to the Transition Services Agreement, Haymaker Services provides certain administrative services and accounting assistance on a transitional basis for total compensation of approximately $2.3 million through December 31, 2018, at which point, the Transition Services Agreement will terminate. The Partnership incurred $1.4 million in transition service fees for the three and nine months ended September 30, 2018. Such costs are included in general and administrative expense in the accompanying unaudited condensed consolidated statements of operations.

NOTE 15—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership has situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. The Partnership is currently assessing such a situation relating to certain non-producing acreage in its portfolio, the resolution of which is not expected to have a material impact on the Partnership’s condensed consolidated financial statements, and no amounts have been accrued as of September 30, 2018.

NOTE 16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to September 30, 2018 in the preparation of its condensed consolidated financial statements.

On October 1, 2018, the Partnership completed an underwritten public offering of 3,000,000 common units. On October 4, 2018, the Partnership issued an additional 450,000 common units in connection with the exercise of the underwriters’ option to purchase additional common units pursuant to the offering. The Partnership received proceeds from the offering of approximately $61.8 million, net of the underwriting discount and offering expenses. The Partnership used the net proceeds to purchase OpCo Common Units. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under the Partnership’s Amended Credit Agreement.

On October 26, 2018 the Board of Directors declared a quarterly cash distribution of $0.45 per common unit for the quarter ended September 30, 2018. The distribution will be paid on November 12, 2018 to common unitholders of record as of the close of business on November 5, 2018.

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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, 2017.

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

Unless otherwise indicated in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for periods on or prior to February 7, 2017 refers only to Rivercrest Royalties, LLC (“the Predecessor” or “Rivercrest”), the Predecessor for accounting and financial reporting purposes and does not include the results of the Partnership as a whole. The interests underlying the oil, natural gas and natural gas liquids(“NGL”) production revenues of our Predecessor represent approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

References to the "Haymaker Acquisition" refer to the acquisition of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, L.P. (together, "Haymaker"), which closed on July 12, 2018. The assets acquired in the Haymaker Acquisition, consist of approximately 5.4 million gross acres and 43,000 net royalty acres.

Cautionary Statement Regarding Forward‑Looking Statements

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

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

the risk that the Tax Election and the Restructuring disrupts current plans and operations;

the amount of the costs, fees, expenses and charges related to the Tax Election and the Restructuring;

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

our ability to execute our business strategies;

the volatility of realized prices for oil, natural gas and NGLs;

the level of production on our properties;

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

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

our ability to replace our reserves;

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

general economic, business or industry conditions;

competition in the oil and natural gas industry;

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

title defects in the properties in which we invest;

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

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

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

the availability of transportation facilities;

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

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

future operating results;

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

operating hazards faced by the operators of our properties;

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

certain factors discussed elsewhere in this report.

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 of America (“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 our Sponsors, the Contributing Parties and third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.

As of September 30, 2018, on a combined basis after taking the Haymaker Acquisition into account, we owned mineral and royalty interests in approximately 7.0 million gross acres and overriding royalty interests in approximately 4.1 million gross acres, with approximately 53% of our aggregate acres located in the Permian and Midcontinent basins. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of September 30, 2018,

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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 nearly every major onshore basin across the continental United States and include ownership in over 84,000 gross producing wells, including over 38,000 wells in the Permian Basin.

The following table summarizes our ownership in United States basins and producing regions, information about the well in which we have a mineral or royalty interest and the number of active rigs operating on our acreage as of September 30, 2018:


			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	2,542,762	20,242	1,539	1,275	38,674	28
Mid‑Continent	3,344,254	38,716	1,527	790	9,408	18
Haynesville	619,847	6,430	1,609	615	7,602	5
Appalachia	283,702	8,899	1,302	492	1,938	-
Bakken	978,881	5,174	420	339	2,624	-
Eagle Ford	361,111	3,674	462	305	1,603	4
Rockies	39,808	564	608	318	11,883	15
Other	2,952,913	31,557	1,079	593	10,533	1
Total	11,123,278	115,256	8,546	4,727	84,265	71

(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 "Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves" in our Annual Report on Form 10-K.

(2)

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

Our management's review of the estimated proved reserves relating to the Haymaker Acquisition indicated estimated proved reserves of 5,912 MBoe as of December 31, 2017, which estimated proved reserves were determined using $51.34 per barrel of oil and $2.98 per MMBtu of gas. Such prices were determined using the average of the historical first-day-of-the-month prices for the twelve months ended December 31, 2017 in accordance with the United States Securities and Exchange Commission (“SEC”) guidelines. Approximately 57% of these reserves were oil and natural gas liquids and 100% were proved developed. In addition, we estimate that the average estimated five-year decline rate for our combined proved developed producing reserves is less than 11%. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates prepared by one engineer may vary from those prepared by another. Estimates of proved reserves for our combined oil and gas properties as of December 31, 2018 will be prepared by Ryder Scott Company, L.P. using the information available at that time. Upon completion of their review, the estimate of the proved reserves for our oil and gas properties as of December 31, 2018 will be different from the estimate of the proved reserves for our oil and gas properties as of December 31, 2017, and the estimates of proved reserves relating to the Haymaker Acquisition as of December 31, 2018 will be different from our management's estimates of such reserves as of December 31, 2017.

Recent Developments

Recapitalization Agreement

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EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC (together, the “Haymaker Holders”) and the 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.

Tax Status Election and Restructuring

Simultaneously with the effectiveness of these agreements, the transactions described in the Recapitalization Agreement were consummated.

Third Quarter Distributions

In August 2018, the Partnership paid a quarterly cash distribution on the Series A Preferred Units of $0.7 million for the quarter ended September 30, 2018, which is included in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2018.

On October 26, 2018, the Board of Directors declared a quarterly cash distribution of $0.45 per common unit for the quarter ended September 30, 2018. The distribution will be paid on November 12, 2018 to common unitholders of record as of the close of business on November 5, 2018.

The Haymaker Holders and the Foundation received a cash distribution equal to 2% on their respective Class B Contribution. The distribution on the Class B units is included in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2018.

Business Environment

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. During the nine months ended September 30, 2018, West Texas Intermediate (“WTI”) ranged from a low of $59.20 per Bbl on February 9, 2018 to a high of $77.41 per Bbl on June 27, 2018, and during the nine months ended September 30, 2017, WTI ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $54.48 per Bbl on February 23, 2017. During the nine months ended September 30, 2018, the Henry Hub spot market price of natural gas ranged from a low of $2.49 per MMBtu on February 16, 2018 to a high of $6.24 per MMBtu on January 3, 2018, and during the nine months ended September 30, 2017, the Henry Hub spot market price of natural gas ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017. On October 15, 2018, the WTI posted price for crude oil was $71.84 per Bbl and the Henry Hub spot market price of natural gas was $3.26 per MMBtu.

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The following table, as reported by the United States Energy Information Administration (“EIA”), sets forth the average prices for oil and natural gas for the three and nine months ended September 30, 2018 and 2017:


	Three Months Ended September 30,				Nine Months Ended September 30,
EIA Average Price:	2018		2017		2018		2017
Oil (Bbl)	$	69.69	$	48.18	$	66.93	$	49.30
Natural gas (MMBtu)	$	2.93	$	2.95	$	2.95	$	3.01

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 was 1,054 active rigs at September 30, 2018, a 12% increase from 940 active rigs at September 30, 2017. In addition, according to the Baker Hughes Unites States Rotary Rig count, rig activity in the 20 states in which we owned mineral and royalty interests, prior to the Haymaker Acquisition, increased 13% from 857 active rigs at September 30, 2017 to 971 active rigs at September 30, 2018. Following the Haymaker Acquisition, we now own mineral and royalty interests in 28 states. The Baker Hughes United States Rotary Rig count, rig activity in the 28 states in which we own mineral and royalty interests increased 12% from 935 active rigs at September 30, 2017 to 1,048 active rigs at September 30, 2018. The active rig count across our acreage at September 30, 2018 remained relatively steady at 71 rigs when compared to the 72 active rigs at August 1, 2018.

Sources of Our Revenue

Our revenues and our Predecessor’s revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. 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:


	Partnership								Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,
	2018		2017		2018		2017		2017
Royalty income
Oil sales	53	%	57	%	57	%	59	%	55	%
Natural gas sales	33	%	30	%	28	%	29	%	36	%
NGL sales	12	%	11	%	12	%	11	%	9	%
Lease bonus and other income	2	%	2	%	3	%	1	%	-	%
	100	%	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 2020. Our Predecessor did not enter into hedging arrangements to establish, in advance, a price for the sale of the oil, natural gas and NGLs produced from our mineral and royalty interests. As a result, our Predecessor may have realized the benefit of any short‑term increase in the price of oil, natural gas and NGLs, but was not protected against decreases in price, and if the price of oil, natural gas and NGLs decreased significantly, our Predecessor’s business, results of operation and cash available for distribution may have been materially adversely affected.

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,

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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) before interest expense, net of capitalized interest, non‑cash unit‑based compensation, transaction costs, mark-to-market gains and losses on open commodity derivative instruments, impairment of oil and natural gas properties, income taxes and depreciation, depletion and accretion 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 and 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.

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).


	Partnership								Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,
	2018		2017		2018		2017		2017
Reconciliation of net (loss) income to Adjusted EBITDA:
Net (loss) income before Series A preferred unit distribution and accretion	$	(999,392)	$	119,029	$	(52,445,568)	$	653,898	$	(496,856)
Depreciation, depletion and accretion expense		7,607,137		4,488,915		15,494,439		11,156,292		113,639
Interest expense		1,843,483		225,302		2,677,083		468,429		39,307
Provision for income taxes		1,977,116		—		1,977,116		—		—
EBITDA		10,428,344		4,833,246		(32,296,930)		12,278,619		(343,910)
Impairment of oil and natural gas properties		—		—		54,753,444		—		—
Transaction costs		—		—		1,188,967		—		—
Unit‑based compensation		751,074		434,197		2,143,047		569,889		50,422
Change in fair value of open commodity derivative instruments		2,813,933		—		3,495,463		—		—
Adjusted EBITDA	$	13,993,351	$	5,267,443	$	29,283,991	$	12,848,508	$	(293,488)
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		1,243,398		166,707		2,220,885		276,246		34,505
Cash distributions on Series A preferred units		705,834		—		705,834		—		—
Distributions on Class B units		12,953		—		12,953		—		—
Cash available for distribution	$	12,031,166	$	5,100,736	$	26,344,319	$	12,572,262	$	(327,993)

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	Partnership								Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,
	2018		2017		2018		2017		2017
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	684,990	$	5,387,438	$	18,592,070	$	13,965,478	$	186,719
Interest expense		1,843,483		225,302		2,677,083		468,429		39,307
Current income tax expense		501,468		—		501,468		—		—
Impairment of oil and natural gas properties		—		—		(54,753,444)		—		—
Amortization of loan origination costs		(177,026)		(15,625)		(208,276)		(41,667)		(4,241)
Amortization of tenant improvement allowance		—		—		—		—		2,864
Unit-based compensation		(751,074)		(434,197)		(2,143,047)		(569,889)		(50,422)
Change in fair value of open commodity derivative instruments		(2,813,933)		—		(3,495,463)		—		—
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		8,976,629		555,908		8,781,555		496,886		(14,551)
Accounts receivable and other current assets		200,125		65,175		190,093		258,785		(333,056)
Accounts payable		3,749,971		228,080		(1,172,615)		(152,569)		(247,972)
Other current liabilities		(1,786,289)		(1,178,835)		(1,266,354)		(2,146,834)		77,442
EBITDA	$	10,428,344	$	4,833,246	$	(32,296,930)	$	12,278,619	$	(343,910)
Add:
Impairment of oil and natural gas properties		—		—		54,753,444		—		—
Transaction costs		—		—		1,188,967		—		—
Unit‑based compensation		751,074		434,197		2,143,047		569,889		50,422
Change in fair value of open commodity derivative instruments		2,813,933		—		3,495,463		—		—
Adjusted EBITDA	$	13,993,351	$	5,267,443	$	29,283,991	$	12,848,508	$	(293,488)

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

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

No Effect Given to Transactions in Connection with Initial Public Offering

The historical financial statements of our Predecessor included in this Quarterly Report do not reflect the financial condition or results of operations of the Partnership. Further, these historical financial statements do not give effect to the transactions that were completed in connection with the closing of the Partnership’s IPO. In connection with our IPO, our Predecessor assigned all of its non‑operating working interests to an affiliate that was not contributed to us, and all of the membership interests of our Predecessor were contributed to us in exchange for common units and a portion of the net proceeds from the IPO. In addition, the Contributing Parties directly or indirectly contributed to us the other assets that made up our initial assets in exchange for common units and a portion of the net proceeds from the IPO. The combination of the assets contributed to us by the Contributing Parties was accounted for at fair value as an asset acquisition. The fair value of the purchase price consideration was based upon the value of the common units purchased in the Partnership’s IPO by third-party investors.

The historical financial data of our Predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the Partnership as a whole and may not provide an accurate indication of what our actual results would have been if the transactions completed in connection with our IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

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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.

The substantial majority of our proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. In accordance with Staff Accounting Bulletin Topic 12: D 3a., management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and requested and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and remained effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that we were required to assess the fair value of the acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of the acquired assets in the full-cost ceiling test would not be appropriate.

Due to the exemption expiring we are required to assess the fair value of our assets for impairment. No impairment expense was recorded during the three months ended September 30, 2018. We recorded an impairment on our oil and natural gas properties of $54.8 million during the nine months ended September 30, 2018 as a result of our quarterly full cost ceiling analysis during the three months ended March 31, 2018. No impairment expense was recorded for the period from February 8, 2017 to September 30, 2017 or for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”).

Credit Agreements

In connection with our IPO, we entered into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.

Amendment to the Existing Credit Agreement

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Partnership, (iii) limitations on redemptions of the 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 Existing Credit Agreement, which varies based upon the level of borrowing base usage, by 0.25% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 2.00% to 3.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement) and (vi) the addition of certain restrictions on the Partnership’s and the Operating Company’s ability to take certain actions or amend their organizational documents. Additionally, the Credit Agreement Amendment permitted the transactions to effect the change of the Partnership’s United States federal income tax status from a pass-through partnership to an entity taxable as a corporation by means of a “check-the-box” election and to effect an “up-C” structure.

As of September 30, 2018, we had borrowed $1.5 million to fund certain IPO-related transaction expenses and our entrance into a management services agreement with Kimbell Operating Company, LLC (“Kimbell Operating”), the acquisition of various mineral and royalty interests throughout the 2017 period for an aggregate purchase price of approximately $29.3 million, and $124.4 million primarily for the Haymaker Acquisition. During the nine months ended September 30, 2018, we repaid $6.9 million of the total outstanding borrowings. For the three months ended September 30, 2018 and 2017, we incurred $1.8 million and $0.2 million, respectively, in interest expense. For the nine months ended September 30, 2018 and the period from February 8, 2017 to September 30, 2017, we incurred $2.7 million and $0.5 million, respectively, in interest expense.

For the Predecessor 2017 Period, our Predecessor’s interest expense was de minimis. We did not assume any indebtedness of our Predecessor in connection with the IPO.

Ongoing Acquisition Activities, Including Potential Dropdowns

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from affiliates of our Sponsors, and the Contributing Parties, as well as from third 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.

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 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.

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Management Services Agreements

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

Transition Services Agreement

On July 12, 2018, pursuant to the Haymaker Acquisition, the Partnership entered into a Transition Services Agreement with Haymaker Services, LLC (“Haymaker Services” and the “Transition Services Agreement”). Pursuant to the Transition Services Agreement, Haymaker Services will provide certain administrative services and accounting assistance on a transitional basis for total compensation of approximately $2.3 million through December 31, 2018, at which point, the Transition Services Agreement will terminate.

Non‑Operated Working Interest Assignment

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

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Results of Operations

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


	Partnership								Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,
	2018		2017		2018		2017		2017
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	21,085,377	$	8,174,195	$	42,741,233	$	20,479,537	$	318,310
Lease bonus and other income		358,215		177,204		1,124,949		177,204		—
Loss on commodity derivative instruments		(3,035,636)		—		(3,858,990)		—		—
Total revenues		18,407,956		8,351,399		40,007,192		20,656,741		318,310
Costs and expenses
Production and ad valorem taxes		1,410,335		778,733		3,031,732		1,602,520		19,651
Depreciation, depletion and accretion expense		7,607,137		4,488,915		15,494,439		11,156,292		113,639
Impairment of oil and natural gas properties		—		—		54,753,444		—		—
Marketing and other deductions		1,689,780		424,702		2,868,655		1,068,509		110,534
General and administrative expenses		4,879,497		2,314,718		11,650,291		5,707,093		532,035
Total costs and expenses		15,586,749		8,007,068		87,798,561		19,534,414		775,859
Operating income (loss)		2,821,207		344,331		(47,791,369)		1,122,327		(457,549)
Other expense
Interest expense		1,843,483		225,302		2,677,083		468,429		39,307
Net income (loss) before income taxes		977,724		119,029		(50,468,452)		653,898		(496,856)
Provision for income taxes		1,977,116		—		1,977,116		—		—
Net (loss) income before Series A preferred unit distribution and accretion		(999,392)		119,029		(52,445,568)		653,898		(496,856)
Distribution and accretion on Series A preferred units		(2,840,456)		—		(2,840,456)		—		—
Net (loss) income		(3,839,848)		119,029		(55,286,024)		653,898		(496,856)
Net loss attributable to noncontrolling interests		(141,003)		—		(141,003)		—		—
Net (loss) income attributable to Kimbell Royalty Partners LP		(3,698,845)		119,029		(55,145,021)		653,898		(496,856)
Distribution on Class B units		(12,953)		—		(12,953)		—		—
Net (loss) income attributable to common units	$	(3,711,798)	$	119,029	$	(55,157,974)	$	653,898	$	(496,856)
Production Data:
Oil (Bbls)		176,789		108,692		394,876		267,966		3,696
Natural gas (Mcf)		2,766,750		888,694		4,750,135		2,205,292		32,961
Natural gas liquids (Bbls)		93,339		46,493		203,839		108,929		1,220
Combined volumes (Boe) (6:1)		731,253		303,301		1,390,404		744,444		10,410

Comparison of the Three Months Ended June 30, 2018 to the Three Months Ended June 30, 2017

Oil, Natural Gas and Natural Gas Liquids Revenues

For the three months ended September 30, 2018, our oil, natural gas and NGL revenues were $21.1 million, an increase of $12.9 million from $8.2 million for the three months ended September 30, 2017. The increase in revenues was primarily attributable to the revenues associated with the Haymaker Acquisition, which represents $10.2 million of the overall increase in oil, natural gas and NGL revenues. Also contributing to the increase was an increase in production from

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the acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production and revenues from those acquired interests and a 47.4% increase in the average prices received for oil production, partially offset by an 8.2% decrease in the average prices received for natural gas.

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 731,253 Boe or 8,546 Boe/d, for the three months ended September 30, 2018, an increase of 427,952 Boe or 5,249 Boe/d, from 303,301 Boe or 3,297 Boe/d, for the three months ended September 30, 2017. The increase in production was primarily attributable to the Haymaker Acquisition, which represents 405,185 Boe or 5,002 Boe/d. Also contributing to the increase was the acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production from those acquired interests.

Our operators received an average of $64.77 per Bbl of oil, $2.56 per Mcf of natural gas and $27.45 per Bbl of NGL for the volumes sold during the three months ended September 30, 2018 and $43.95 per Bbl of oil, $2.79 per Mcf of natural gas and $19.75 per Bbl of NGL for the volumes sold during the three months ended September 30, 2017. The three months ended September 30, 2018 increased 47.4% or $20.82 per Bbl of oil and decreased 8.2% or $0.23 per Mcf of natural gas as compared to the three months ended September 30, 2017. These changes are consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 44.6% or $21.51 per Bbl of oil and decrease of 0.7% or $0.02 per Mcf of natural gas for the comparable periods.

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended September 30, 2018 includes $2.8 million of mark to market losses and $0.2 million loss on settlement of commodity derivative instruments. We did not have any commodity derivative instruments for the three months ended September 30, 2017.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended September 30, 2018 were $1.4 million, an increase of $0.6 million from $0.8 million for the three months ended September 30, 2017. The increase was primarily attributable to the Haymaker Acquisition and to the acquisition of various mineral and royalty interests throughout the 2017 period, and the relevant production from those acquired interests.

Depreciation, Depletion and Accretion Expense

Depreciation, depletion and accretion expense for the three months ended September 30, 2018 was $7.6 million, an increase of $3.1 million from $4.5 million for the three months ended September 30, 2017. The increase in the depreciation, depletion and accretion expense was primarily attributable to the Haymaker Acquisition in the third quarter of 2018.

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 $10.37 for the three months ended September 30, 2018, a decrease of $4.29 per barrel from the $14.66 average depletion rate per barrel for the three months ended September 30, 2017. The decrease was primarily attributable to the $54.8 million of impairment recorded on our oil and natural gas properties during the three months ended March 31, 2018.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

No impairment expense was recorded for the three months ended September 30, 2018 or for the three months ended September 30, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment of oil and natural gas properties for the three months ended September 30, 2017.

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Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post‑production expense. Marketing and other deductions for the three months ended September 30, 2018 were $1.7 million, an increase of $1.3 million from $0.4 million for the three months ended September 30, 2017. The increase in marketing and other deductions was primarily attributable to the Haymaker Acquisition, which represents $1.1 million of the overall increase. Also contributing to the increase was the acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production from those acquired interests.

General and Administrative Expenses

General and administrative expenses for the three months ended September 30, 2018 were $4.9 million, an increase of $2.6 million from $2.3 million for the three months ended September 30, 2017. The increase in general and administrative expenses was primarily attributable to costs incurred during the three months ended September 30, 2018 related to our conversion to a corporation for income tax purposes and an increase in unit-based compensation expense. Additionally, we incurred $1.4 million in general and administrative expense directly related to the Transition Services Agreement with Haymaker Services, LLC (“Haymaker Services” and the “Transition Services Agreement”).

Interest Expense

Interest expense for the three months ended September 30, 2018 was $1.8 million as compared to interest expense of $0.2 million for the three months ended September 30, 2017. This increase was due to debt incurred to fund acquisitions in 2017 and 2018.

Provision for Income Taxes

We recorded a provision for income taxes of $2.0 million for the three months ended September 30, 2018 due to the change in our income tax status. Prior to the third quarter of 2018, we had no provision for or benefit from income taxes. Total income tax expense for the three months ended September 30, 2018 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the impact of discrete items such as $1.5 million of tax expense recognized as a result of the Partnership’s change in tax status and tax expense of $0.5 million recognized in connection with the Preferred Purchase Agreement.

Comparison of the Nine Months Ended September 30, 2018 to the Nine Months Ended September 30, 2017

The period presented for the nine months ended September 30, 2017 includes the results of operations for the period from February 8, 2017 to September 30, 2017 and the Predecessor 2017 Period. The mineral and royalty interests of our Predecessor only represent approximately 11% of our total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

Oil, Natural Gas and Natural Gas Liquids Revenues

For the nine months ended September 30, 2018, our oil, natural gas and NGL revenues were $42.7 million, an increase of $21.9 million, from $20.8 million for the nine months ended September 30, 2017. The increase in revenues was partially attributable to the revenues associated with the Haymaker Acquisition, which represents $10.2 million of the overall increase in oil, natural gas and NGL revenues. The increase in revenues was also attributable to the full period of production from our properties for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 when production prior to February 8, 2017 only includes the results of our Predecessor and does not include the results of the Partnership as a whole. Additionally, we had $29.3 million in acquisitions of various mineral and royalty interests throughout the 2017 period and the nine months ended September 30, 2018 includes the relevant production and revenues from those acquired interests.

Our and our Predecessor’s revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,390,404 Boe or 8,611 Boe/d, for the nine months ended September 30, 2018, an increase of 635,550 Boe or 5,846 Boe/d, from 754,854 Boe or 2,765 Boe/d, for the nine months ended September 30, 2017. The increase in production was primarily attributable to the Haymaker

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Acquisition, which represents 405,185 Boe or 5,002 Boe/d The increase in production volumes was also attributable to the full period of production from our properties for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 when production prior to February 8, 2017 only includes the results of our Predecessor and does not include the results of the Partnership as a whole. Additionally, we had $29.3 million in acquisitions of various mineral and royalty interests throughout the 2017 period and the nine months ended September 30, 2018 includes the relevant production from those acquired interests.

Our operators received an average of $63.35 per Bbl of oil, $2.59 per Mcf of natural gas and $26.58 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2018 and $45.16 per Bbl of oil, $2.78 per Mcf of natural gas and $20.90 per Bbl of NGL for the volumes sold during the nine months ended September 30, 2017. The nine months ended September 30, 2018 increased 40.3% or $18.19 per Bbl of oil and decreased 6.8% or $0.19 per Mcf of natural gas as compared to the nine months ended September 30, 2017. These changes are consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 35.8% or $17.63 per Bbl of oil and decrease of 2.0% or $0.06 per Mcf of natural gas for the comparable periods.

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the nine months ended September 30, 2018 includes $3.5 million of mark to market losses and $0.4 million loss on settlement of commodity derivative instruments. We did not have any commodity derivative instruments for the nine months ended September 30, 2017.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the nine months ended September 30, 2018 were $3.0 million, an increase of $1.4 million from $1.6 million for the nine months ended September 30, 2017. The increase in production and ad valorem taxes was primarily attributable to the full period of production from our properties for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 when production prior to February 8, 2017 only includes the results of our Predecessor and does not include the results of the Partnership as a whole. Also, partially contributing to the increase in production and ad valorem taxes was a $0.7 million increase as a result of the Haymaker Acquisition in the third quarter of 2018. Additionally, we had $29.3 million in acquisitions of various mineral and royalty interests throughout the 2017 period and the nine months ended September 30, 2018 includes the relevant production from those acquired interests.

Depreciation, Depletion and Accretion Expense

Depreciation, depletion and accretion expense for the nine months ended September 30, 2018 was $15.5 million, an increase of $4.2 million from $11.3 million for the nine months ended September 30, 2017. The increase in the depreciation, depletion and accretion expense was primarily attributable to the full period of production from our properties for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 when production prior to February 8, 2017 only includes the results of our Predecessor and does not include the results of the Partnership as a whole. Additionally, we completed the Haymaker Acquisition in the third quarter of 2018 and had $29.3 million in acquisitions of various mineral and royalty interests throughout the 2017 period and the nine months ended September 30, 2018 includes the relevant production from those acquired interests.

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 $11.07 for the nine months ended September 30, 2018, a decrease of $3.71 per barrel from $14.78 average depletion rate per barrel for the nine months ended September 30, 2017. The decrease was primarily attributable to the $54.8 million of impairment recorded on our oil and natural gas properties during the three months ended March 31, 2018.

Impairment of Oil, Natural Gas and Natural Gas Liquids Expense

We recorded an impairment on our oil and natural gas properties of $54.8 million during the nine months ended September 30, 2018 as a result of our quarterly full cost ceiling analysis during the three months ended March 31, 2018.

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No impairment expense was recorded for the nine months ended September 30, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment of oil and natural gas properties for the nine months ended September 30, 2017.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post‑production expense, and our Predecessor’s marketing and other deductions also includes lease operating expenses related to its non‑operated working interests. Marketing and other deductions for the nine months ended September 30, 2018 were $2.9 million, an increase of $1.7 million from $1.2 million for the nine months ended September 30, 2017. The increase in marketing and other deductions was primarily attributable to the Haymaker Acquisition, which represents $1.1 million of the overall increase. Also contributing to the increase in marketing and other deductions was the full period of production from our properties for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 when production prior to February 8, 2017 only includes the results of our Predecessor and does not include the results of the Partnership as a whole. Additionally, we had $29.3 million in acquisitions of various mineral and royalty interests throughout the 2017 period and the nine months ended September 30, 2018 includes the relevant production from those acquired interests.

General and Administrative Expenses

General and administrative expenses for the nine months ended September 30, 2018 were $11.7 million, an increase of $5.5 million from $6.2 million for the nine months ended September 30, 2017. The increase in general and administrative expenses was attributable to costs incurred related to our conversion to a corporation for income tax purposes and the increase in unit-based compensation expense during the nine months ended September 30, 2018. Additionally, we incurred $1.4 million in general and administrative expense directly related to the Transition Services Agreement with Haymaker Services and the nine months ended September 30, 2018 include the Partnership as a whole compared to the nine months ended September 30, 2017, when costs prior to February 8, 2017 only includes the results of our Predecessor and does not include the results of the Partnership as a whole.

Interest Expense

Interest expense for the nine months ended September 30, 2018 was $2.7 million as compared to interest expense of $0.5 million for the nine months ended September 30, 2017. This increase was due to debt incurred to fund acquisitions in 2017 and 2018.

Provision for Income Taxes

We recorded a provision for income taxes of $2.0 million for the nine months ended September 30, 2018 due to the change in our income tax status. Prior to the third quarter of 2018, we had no provision for or benefit from income taxes. Total income tax expense for the nine months ended September 30, 2018 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the impact of discrete items such as $1.5 million of tax expense recognized as a result of the Partnership’s change in tax status and tax expense of $0.5 million recognized in connection with the Preferred Purchase Agreement.

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 Existing Credit Agreement, increasing commitments under the facility from $50.0 million to $200.0 million with an accordion feature permitting aggregate commitments under the 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. The first redetermination date for

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the amended credit facility will be February 1, 2019. As of November 2, 2018, we had an outstanding balance of $87.3 million under our secured revolving credit facility.

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash.” Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. We expect that available cash for each quarter will generally equal or approximate our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs, including replacement or growth capital expenditures, that the Board of Directors may determine is appropriate.

We do not generally intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (replacement capital expenditures), primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. If they believe it is warranted, the Board of Directors may withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the period(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders.

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, the Partnership completed the Haymaker Acquisition funding consideration for the transaction with 10,000,000 common units of the Partnership, net proceeds from the Preferred Units Transaction and borrowings of $124.0 million under the Amended Credit Agreement. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise reserve cash for distributions, or to incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

Because our partnership agreement requires us to distribute an amount equal to all available cash we generate each quarter, our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and NGLs, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of our quarterly distributions may be significant and could result in our not making any distribution for any particular quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The Board of Directors may change our distribution policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters.

In August 2018, the Partnership paid a quarterly cash distribution on the Series A Preferred Units of $0.7 million for the quarter ended September 30, 2018.

Pursuant to the terms of the Recapitalization Agreement, the Haymaker Holders and the Foundation received a cash distribution equal to 2% on their respective Class B Contribution.

October 2018 Equity Offering

On October 1, 2018, we completed an underwritten public offering of 3,000,000 common units. On October 4, 2018, the Partnership issued an additional 450,000 common units in connection with the exercise of the underwriters’ option to purchase additional common units pursuant to the offering. We received proceeds from the offering of

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approximately $61.8 million, net of the underwriting discount and offering expenses. We used the net proceeds to purchase OpCo Common Units. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under our revolving credit facility.

Cash Flows

The table below presents our and our Predecessor’s cash flows for the periods indicated.


	Partnership				Predecessor
	Nine Months Ended September 30,		Period from February 8, 2017 to September 30,		Period from January 1, 2017 to February 7,
	2018		2017		2017
Cash Flow Data:
Cash flows provided by operating activities	$	18,592,070	$	13,965,478	$	186,719
Cash flows used in investing activities		(200,394,775)		(117,190,256)		(523)
Cash flows provided by financing activities		192,705,177		109,451,257		—
Net increase in cash	$	10,902,472	$	6,226,479	$	186,196

Operating Activities

Our and our Predecessor’s operating cash flow is impacted by many variables, the most significant of which is 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 and our Predecessor’s control and are difficult to predict. Cash flows provided by operating activities for the nine months ended September 30, 2018 were $18.6 million, an increase of $4.4 million compared to $14.2 million for the nine months ended September 30, 2017. The increase in cash flows provided by operating activities was primarily attributable to the Haymaker Acquisition and to the full period of production from our properties for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 when production prior to February 8, 2017 only includes the results of our Predecessor and does not include the results of the Partnership as a whole. Additionally, we had $29.3 million in acquisitions of various mineral and royalty interests throughout the 2017 period and the nine months ended September 30, 2018 includes the relevant production and revenues from those acquired interests. To a lesser extent, an increase in the price received for oil production also contributed to the increase in cash flow provided by operating activities.

Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2018 increased by $83.2 million compared to the nine months ended September 30, 2017. For the nine months ended September 30, 2018 we used $210.6 million to fund the Haymaker Acquisition and $0.4 million to fund the remodel of office space, partially offset by $10.6 million in proceeds received from the sale of oil and natural gas properties. For the period from February 8, 2017 to September 30, 2017, we used the $96.2 million in proceeds received from our IPO to pay the cash portion of our acquisition of oil and natural gas properties at the IPO and we used $20.7 million to fund the acquisition of various mineral and royalty interests.

Financing Activities

Cash flows provided by financing activities were $192.7 million for the nine months ended September 30, 2018, an increase of $83.2 million compared to $109.5 million for the nine months ended September 30, 2017. Cash flows provided by financing activities for the nine months ended September 30, 2018 consists of $124.4 million of additional borrowings under our secured revolving credit facility, $103.4 million in proceeds from the issuance of Series A Preferred Units and $0.6 million in contributions from our Class B unitholders, partially offset by $25.4 million of distributions paid to unitholders of common units and Series A Preferred Units, $6.9 million of repayments on our secured revolving credit facility and $3.4 million paid in loan origination costs. During the period from February 8, 2017 to September 30, 2017, we received $96.2 million in proceeds from our IPO, we borrowed $22.2 million, paid a distribution to common unitholders of $8.7 million and paid loan origination costs of $0.3 million.

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Capital Expenditures

During the nine months ended September 30, 2018, we paid approximately $210.6 million in connection with the Haymaker Acquisition. During the period from February 8, 2017 to September 30, 2017, we acquired mineral and royalty interests from the Contributing Parties for common units with a total value at the IPO of $169.1 million and $96.2 million in cash. Additionally, we spent an aggregate amount of $20.7 million for the acquisition of various mineral and royalty interests. During the Predecessor 2017 Period, our Predecessor spent a de minimis amount on additional lease and well equipment and intangible drilling costs related to the Predecessor’s working interests and office equipment.

Indebtedness

Revolving Credit Agreement

We entered into a $50.0 million revolving credit facility in connection with our IPO, which is secured by substantially all of our assets and the assets of our wholly owned subsidiaries. In connection with the Haymaker Acquisition the Partnership amended its secured revolving credit facility. Under the secured revolving credit facility, availability under the facility will continue to equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will continue to be re-determined semi-annually on February 1 and August 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 and will mature on February 8, 2022. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Pursuant to the amendment, the aggregate commitments remain at $200.0 million providing for maximum availability under the revolving credit facility of $200.0 million with the first redetermination date to be February 1, 2019. The amended secured revolving credit facility permits aggregate commitments under the 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 secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facility also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control. As of November 2, 2018, we have borrowed $155.2 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating, and the acquisition of various mineral and royalty interests for an aggregate purchase price of approximately $153.7 million. During the nine months ended September 30, 2018, we repaid $6.9 million of the total outstanding borrowings. Subsequent to September 30, 2018, we repaid an additional $61.0 million of the total outstanding borrowings, primarily funded by the equity offering.

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, 2017.

Contractual Obligations and Off‑Balance Sheet Arrangements

Other than the increase in long-term debt as a result of the Haymaker Acquisition, 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, 2017. As of September 30, 2018, neither we, nor our Predecessor had any off‑balance sheet arrangements other than operating leases.

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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.

We hedge our daily production based on the amount of debt and/or preferred equity as a percent of our enterprise value. Prior to the Haymaker Acquisition, this amount constituted approximately 10% of daily oil and natural gas production. Following the closing of the Haymaker Acquisition, we hedged daily oil and natural gas production of approximately 30% of our post-acquisition production. After giving effect to the pay down of borrowings under the revolving credit facility in early October 2018, we have hedged daily oil and natural gas production of approximately 25% of our production.

At September 30, 2018, our 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.

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 the Partnership’s commodity derivatives.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of September 30, 2018, we had one counterparty, which is also one of the lenders under our credit facility.

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

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of September 30, 2018, we had total borrowings outstanding under our secured revolving credit facility of $148.3 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 $1.5 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a‑15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a‑15(e) and 15d‑15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2018.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2018 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

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition, cash flows or results of operations.

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, 2017 and Quarterly Report on Form 10-Q for the quarter ended June 30, 2018. Due to the change in our federal income tax status, the risks described under “Tax Risks to Common Unitholders” in our Annual Report on Form 10-K for the year ended December 31, 2017 are no longer applicable to us or our common units.

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 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)
4.1	—	Registration Rights Agreement, dated as of July 12, 2018, by and among Kimbell Royalty Partners, LP, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, Haymaker Minerals & Royalties, LLC, AP KRP Holdings, L.P., ATCF SPV, L.P., Zeus Investments, L.P., Apollo Kings Alley Credit SPV, L.P., Apollo Thunder Partners, L.P., AIE III Investments, L.P., Apollo Union Street SPV, L.P., Apollo Lincoln Private Credit Fund, L.P, Apollo SPN Investments I (Credit), LLC and AA Direct, L.P. (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 18, 2018)
10.1	—	Amendment No. 1 to Credit Agreement, dated as of July 12, 2018, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto 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 July 18, 2018)

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10.2	—	Board Representation and Observation Agreement, dated as of July 12, 2018, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell GP Holdings, LLC, AA Direct, L.P., AP KRP Holdings, L.P., AIE III Investments, L.P., Apollo Kings Alley Credit SPV, L.P., Apollo SPN Investments I (Credit), LLC, Apollo Thunder Partners, L.P., ATCF SPV, L.P., Apollo Union Street SPV, L.P., Zeus Investments, L.P. and Apollo Lincoln Private Credit Fund, L.P. (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 18, 2018)
10.3	—	Voting Agreement, dated as of July 12, 2018, by and between Haymaker Minerals & Royalties, LLC and Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 10.3 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 18, 2018)
10.4	—	Voting Agreement, dated as of July 12, 2018, by and among EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC and Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 10.4 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 18, 2018)
10.5	—	Transition Services Agreement, dated as of July 12, 2018, by and between Kimbell Royalty Partners, LP and Haymaker Services, LLC (incorporated by reference to Exhibit 10.5 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 18, 2018)
10.6	—	Recapitalization Agreement, dated as of July 24, 2018, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Operating, LLC, Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, the Kimbell Art Foundation and Haymaker Resources, LP (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 27, 2018)
10.7	—	First Amendment to the Securities Purchase Agreements, dated as of July 11, 2018, by and among Haymaker Resources, LP, Haymaker Minerals & Royalties, LLC, Haymaker Services, LLC and Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 10.9 to Kimbell Royalty Partners, LP’s Form 10-Q filed on August 10, 2018)
10.8		Exchange Agreement, dated as of September 23, 2018, by and among Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, the Kimbell Art Foundation, Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)
10.9		First Amendment to the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)
31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a‑14(a)/15d‑14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a‑14(a)/15d‑14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350
101.INS**	—	XBRL Instance Document.
101.SCH**	—	XBRL Taxonomy Extension Schema Document
101.CAL**	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	—	XBRL Taxonomy Extension Presentation Linkbase Document

* —filed herewith

** —submitted electronically herewith

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SIGNATURES

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


	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner

Date: November 9, 2018	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: November 9, 2018	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer