krp_Current_Folio

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 March 31, 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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

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


Large accelerated filer	◻	Accelerated filer	◻
Non-accelerated filer	☒	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 May 4, 2018, 16,834,984 common units of the registrant were outstanding.

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31,		December 31,
	2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	6,836,524	$	5,625,495
Oil, natural gas and NGL receivables		6,560,310		6,792,837
Accounts receivable and other current assets		371,572		236,673
Total current assets		13,768,406		12,655,005
Property and equipment, net		128,776		165,232
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting		297,624,476		297,609,797
Less: accumulated depreciation, depletion, accretion and impairment		(74,559,676)		(15,394,238)
Total oil and natural gas properties		223,064,800		282,215,559
Loan origination costs, net		239,583		255,208
Total assets	$	237,201,565	$	295,291,004

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities
Accounts payable	$	695,280	$	316,486
Other current liabilities		1,282,631		1,746,662
Commodity derivative liabilities		290,333		183,957
Total current liabilities		2,268,244		2,247,105
Commodity derivative liabilities		240,954		134,872
Long-term debt		30,843,593		30,843,593
Total liabilities		33,352,791		33,225,570
Commitments and contingencies
Partners' capital		203,848,774		262,065,434
Total liabilities and partners' capital	$	237,201,565	$	295,291,004

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

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Partnership				Predecessor
	Three Months Ended March 31,		Period from February 8, 2017 to March 31,		Period from January 1, 2017 to February 7,
	2018		2017		2017
Revenue
Oil, natural gas and NGL revenues	$	11,176,303	$	4,553,344	$	318,310
Loss on commodity derivative instruments		(284,965)		—		—
Total revenues		10,891,338		4,553,344		318,310
Costs and expenses
Production and ad valorem taxes		816,001		206,106		19,651
Depreciation, depletion and accretion expense		4,455,708		2,535,660		113,639
Impairment of oil and natural gas properties		54,753,444		—		—
Marketing and other deductions		569,842		257,126		110,534
General and administrative expense		2,770,772		1,211,082		532,035
Total costs and expenses		63,365,767		4,209,974		775,859
Operating (loss) income		(52,474,429)		343,370		(457,549)
Other expense
Interest expense		350,042		60,152		39,307
Net (loss) income	$	(52,824,471)	$	283,218	$	(496,856)

Net (loss) income attributable to common units
Basic	$	(3.23)	$	0.02	$	(0.82)
Diluted	$	(3.23)	$	0.02	$	(0.82)
Weighted average number of common units outstanding
Basic		16,345,117		16,332,708		604,137
Diluted		16,345,117		16,332,708		604,137

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

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(Unaudited)


	Units		Total
Partners' capital - December 31, 2017		16,509,799	$	262,065,434

Distributions to unitholders		—		(6,061,123)

Restricted units granted, net of forfeitures		325,185		—

Unit-based compensation		—		668,934

Net loss		—		(52,824,471)

Partners' capital - March 31, 2018		16,834,984	$	203,848,774

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

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Partnership				Predecessor
	Three Months Ended March 31,		Period from February 8, 2017 to March 31,		Period from January 1, 2017 to February 7,
	2018		2017		2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(52,824,471)	$	283,218	$	(496,856)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and accretion expense		4,455,708		2,535,660		113,639
Impairment of oil and natural gas properties		54,753,444		—		—
Amortization of loan origination costs		15,625		10,417		4,241
Amortization of tenant improvement allowance		—		—		(2,864)
Unit-based compensation		668,934		—		50,422
Loss on commodity derivative instruments		212,458		—		—
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		232,527		(1,657,446)		14,551
Accounts receivable and other current assets		(134,899)		(276,026)		333,056
Accounts payable		378,794		664,859		247,972
Other current liabilities		(464,031)		1,151,511		(77,442)
Net cash provided by operating activities		7,294,089		2,712,193		186,719
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(7,259)		(7,815)		—
Deposits on oil and natural gas properties		—		(2,377,500)		—
Purchase of oil and natural gas properties		(14,678)		(96,255,000)		(523)
Net cash used in investing activities		(21,937)		(98,640,315)		(523)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from initial public offering		—		96,255,000		—
Distributions to unitholders / members		(6,061,123)		—		—
Borrowings on long-term debt		—		3,877,500		—
Payment of loan origination costs		—		(312,500)		—
Net cash (used in) provided by financing activities		(6,061,123)		99,820,000		—
NET INCREASE IN CASH AND CASH EQUIVALENTS		1,211,029		3,891,878		186,196
CASH AND CASH EQUIVALENTS, beginning of period		5,625,495		—		505,880
CASH AND CASH EQUIVALENTS, end of period	$	6,836,524	$	3,891,878	$	692,076
Supplemental cash flow information:
Cash paid for interest	$	474,676	$	3,914	$	34,505
Cash paid for taxes	$	—	$	—	$	5,355
Non-cash investing and financing activities:
Capital expenditures and consideration payable included in accounts payable and other liabilities	$	—	$	67,700	$	—
Capital expenditures through issuance of common units	$	—	$	176,404,698	$	—

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

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, Rivercrest Royalties, LLC, 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 (“ARO”) to an affiliated entity that was not contributed to the Partnership.

Basis of Presentation

The accompanying unaudited interim 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 U.S. Securities and Exchange Commission (“SEC”). As a result, the accompanying unaudited interim consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim 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 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.

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 three months ended March 31, 2018.

Recently Issued Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 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 primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases and is still assessing the impact it will have on our financial statements.

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

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 consolidated financial statements after the adoption of ASC 606. Upon adoption the Partnership had not altered 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.

NOTE 3—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 March 31, 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.

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.

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 consolidated statement of operations and consisted of the following:


	Three Months Ended March 31,
	2018
Beginning fair value of commodity derivative instruments	$	(318,829)
Loss on commodity derivative instruments		(284,965)
Net cash paid on settlements of derivative instruments		72,507
Ending fair value of commodity derivative instruments	$	(531,287)

At March 31, 2018, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps


	Notional	Weighted Average
	Volumes (MBbls)	Fixed Price (per Bbl)
April 2018 - December 2018	32,450	$	56.00
January 2019 - December 2019	43,070	$	53.07
January 2020 - March 2020	11,011	$	56.03

Natural Gas Price Swaps


	Notional	Weighted Average
	Volumes (MMBtu)	Fixed Price (per MMBtu)
April 2018 - December 2018	265,650	$	2.71
January 2019 - December 2019	352,590	$	2.76
January 2020 - March 2020	96,915	$	2.94

NOTE 4—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, accounts payable and other current liabilities included in the unaudited consolidated balance sheets approximated fair value at March 31, 2018 and December 31, 2017. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment and related impairments, which are calculated using Level 3 inputs, are discussed in Note 5.

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 months ended March 31, 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 5—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consists of the following:


	March 31,		December 31,
	2018		2017
Oil and natural gas properties
Proved properties	$	297,624,476	$	297,609,797
Less: accumulated depreciation, depletion and impairment		(74,559,676)		(15,394,238)
Net oil and natural gas properties	$	223,064,800	`	282,215,559

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

NOTE 6—LONG-TERM DEBT

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 equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will 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. In

connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0 million. The secured revolving credit facility permits aggregate commitments to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The secured revolving credit facility 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. As of March 31, 2018, the Partnership’s outstanding balance was $30.8 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of March 31, 2018.

During the three months ended March 31, 2018, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% and Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the three months ended March 31, 2018, the weighted average interest rate on the Partnership’s outstanding borrowings was 4.09%.

NOTE 7—COMMON UNITS

Q1 2018 Activity

On January 26, 2018, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.36 per common unit for the quarter ended December 31, 2017. The distribution was paid on February 14, 2018 to unitholders of record as of the close of business on February 7, 2018.

On January 26, 2018, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of a total of 326,654 restricted units to certain employees, directors and consultants under the Long-Term Incentive Plan (“LTIP”). Such grants were made on January 29, 2018.

As of March 31, 2018, 16,834,984 common units of the Partnership were outstanding.

Q1 2017 Activity

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

NOTE 8—EARNINGS (LOSS) PER UNIT

Basic earnings per unit (“EPU”) is calculated by dividing net income (loss) 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 9—Unit-Based Compensation. The calculation of diluted net loss per share for the three-months ended March 31, 2018 excludes 488,756 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 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 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 (loss) earnings per share:


	Partnership				Predecessor
	Three Months Ended March 31,		Period from February 8, 2017 to March 31,		Period from January 1, 2017 to February 7,
	2018		2017		2017
Net (loss) income	$	(52,824,471)	$	283,218	$	(496,856)

Net (loss) income attributable to common units
Basic	$	(3.23)	$	0.02	$	(0.82)
Diluted	$	(3.23)	$	0.02	$	(0.82)
Weighted average number of common units outstanding
Basic		16,345,117		16,332,708		604,137
Diluted		16,345,117		16,332,708		604,137

NOTE 9—UNIT-BASED COMPENSATION

The Partnership’s LTIP authorizes grants of up to 2,041,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued under our LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants will be accrued for services provided during the intervening periods between the grant and vesting dates, utilizing then-current fair values for the awards and applying mark-to-market accounting until actual vesting occurs.

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 and directors is determined by utilizing the market value of our common units on the respective grant date. The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs. The following table presents a summary of the Partnership’s unvested common units.


		Weighted				Weighted
		Average				Average
		Grant-Date		Market-Date		Remaining
		Fair Value		Fair Value		Contractual
	Units	per Unit		per Unit		Term
Unvested at December 31, 2017	167,571	$	18.655	$	16.250	1.364 years
Granted - service condition employees	322,828		19.100		-	-
Granted - service condition consultants	3,826		-		19.000	-
Forfeited	(1,469)		-		-	-
Vested	(4,000)		-		-	-
Unvested at March 31, 2018	488,756	$	18.982	$	19.000	1.591 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. The options carried a distribution right, whereby the option holder received distributions that were commensurate with those given to holders of membership units.

A summary of the Predecessor’s option activity as of February 7, 2017 is as follows:


				Weighted
		Weighted		Average
		Average		Remaining
		Exercise		Contractual
	Units	Price		Term
Outstanding, January 1, 2017	110,000	$	100	8.00 years
Granted	—		—	—
Forfeited	—		—	—
Exercised	—		—	—
Outstanding, February 7, 2017	110,000	$	100	7.92 years
Exercisable, February 7, 2017	—	$	—	—

For the Predecessor 2017 Period, 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 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 10—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 March 31, 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 Predecessor 2017 Period, the Predecessor had certain related party receivables and payables; however, such amounts were de minimis.

NOTE 11—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 10―Related Party Transactions.

NOTE 12—COMMITMENTS AND CONTINGENCIES

The Partnership is involved in disputes or legal actions arising in the ordinary course of business. Management does not believe the outcome of such disputes or legal actions will have a material adverse effect on the Partnership’s consolidated financial statements, and no amounts have been accrued at March 31, 2018.

NOTE 13—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to March 31, 2018 in the preparation of its consolidated financial statements.

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 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 the Predecessor for accounting 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.

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. Factors that could cause our actual results to differ materially from the results contemplated by such forward‑looking statements include:

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;

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.

All forward‑looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

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”). 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 March 31, 2018, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 2.0 million gross acres, with approximately 35% of our aggregate acres located in the Permian Basin. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of March 31, 2018, 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 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 50,000 gross producing wells, including over 30,000 wells in the Permian Basin.

Recent Developments

Commodity Derivative Instruments

On March 29, 2018, we entered into additional oil and natural gas fixed price swaps with Frost Bank for the first quarter of 2020. The fixed price swaps consist of 11,011 Bbl of oil at a fixed rate of $56.03 per Bbl and 96,915 MMBtu of natural gas at a fixed rate of $2.94 per MMBtu.

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 three months ended March 31, 2018, West Texas Intermediate (“WTI”) ranged from a low of $59.20 per Bbl on February 9, 2018 to a high of $66.27 per Bbl on January 26, 2018, and during the three months ended March 31, 2017, WTI ranged from a low of $47.00 per Bbl on March 23, 2017 to a high of $54.48 per Bbl on February 23, 2017. During the three months ended March 31, 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 three months ended March 31, 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 April 23, 2018, the WTI posted price for crude oil was $67.61 per Bbl and the Henry Hub spot market price of natural gas was $2.78 per MMBtu.

The following table, as reported by the U.S. Energy Information Administration (“EIA”), sets forth the average prices for oil and natural gas for the three months ended March 31, 2018 and 2017:


	For the three months ended March 31,
EIA Average Price:	2018		2017
Oil (Bbl)	$	62.91	$	51.77
Natural gas (MMBtu)	$	3.08	$	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 U.S. Rotary Rig count was 993 active rigs at March 31, 2018, a 21% increase from 824 active rigs at March 31, 2017. In addition, according to the Baker Hughes U.S. Rotary Rig count, rig activity in the 20 states in which we own mineral and royalty interests increased 21% from 750 active rigs at March 31, 2017 to 905 active rigs at March 31, 2018. The active rig count across our acreage at March 31, 2018 totaled 23 rigs, a 21% increase compared to the 19 rigs at year-end 2017. As of April 25, 2018, our active rig count increased to 25 rigs.

Sources of Our Revenue

Our revenues and our Predecessor’s revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. For the three months ended March 31, 2018, our revenues were generated 60% from oil sales, 24% from natural gas sales, 13% from NGL sales and 3% from other sales. For the period from February 8, 2017 to March 31, 2017, our revenues were generated 62% from oil sales, 27% from natural gas sales and 11% from NGL sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined three months ended March 31, 2017, the revenues were generated 61% from oil sales, 28% from natural gas sales and 11% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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

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 March 31,		Period from February 8, 2017 to March 31,		Period from January 1, 2017 to February 7,
	2018		2017		2017
Reconciliation of net (loss) income to Adjusted EBITDA:
Net (loss) income	$	(52,824,471)	$	283,218	$	(496,856)
Depreciation, depletion and accretion expense		4,455,708		2,535,660		113,639
Interest expense		350,042		60,152		39,307
EBITDA		(48,018,721)		2,879,030		(343,910)
Impairment of oil and natural gas properties		54,753,444		—		—
Unit‑based compensation		668,934		—		50,422
Unrealized loss on commodity derivative instruments		212,458		—		—
Adjusted EBITDA	$	7,616,115	$	2,879,030	$	(293,488)
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		474,676		3,914		34,505
Cash available for distribution	$	7,141,439	$	2,875,116	$	(327,993)


	Partnership				Predecessor
	Three Months Ended March 31,		Period from February 8, 2017 to March 31,		Period from January 1, 2017 to February 7,
	2018		2017		2017
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	7,294,089	$	2,712,193	$	186,719
Interest expense		350,042		60,152		39,307
Impairment of oil and natural gas properties		(54,753,444)		—		—
Amortization of loan origination costs		(15,625)		(10,417)		(4,241)
Amortization of tenant improvement allowance		—		—		2,864
Unit-based compensation		(668,934)		—		(50,422)
Unrealized loss on commodity derivative instruments		(212,458)		—		—
Changes in operating assets and liabilities:
Oil, natural gas and NGL revenues receivable		(232,527)		1,657,446		(14,551)
Accounts receivable and other current assets		134,899		276,026		(333,056)
Accounts payable		(378,794)		(664,859)		(247,972)
Other current liabilities		464,031		(1,151,511)		77,442
EBITDA	$	(48,018,721)	$	2,879,030	$	(343,910)
Add:
Impairment of oil and natural gas properties		54,753,444		—		—
Unit‑based compensation		668,934		—		50,422
Loss on commodity derivative instruments		212,458		—		—
Adjusted EBITDA	$	7,616,115	$	2,879,030	$	(293,488)

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

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

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 U.S. Securities and Exchange Commission (“SEC”) to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the 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 recorded an impairment on our oil and natural gas properties of $54.8 million during the three months ended March 31, 2018 as a result of our quarterly full cost ceiling analysis. No impairment expense was recorded for the period from February 8, 2017 to March 31, 2017 or for 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. As of March 31, 2018, we had borrowed $30.8 million to fund certain IPO-related transaction expenses, our entrance into a

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 March 31,		Period from February 8, 2017 to March 31,		Period from January 1, 2017 to February 7,
	2018		2017		2017
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	11,176,303	$	4,553,344	$	318,310
Loss on commodity derivative instruments		(284,965)		—		—
Total revenues		10,891,338		4,553,344		318,310
Costs and expenses
Production and ad valorem taxes		816,001		206,106		19,651
Depreciation, depletion and accretion expense		4,455,708		2,535,660		113,639
Impairment of oil and natural gas properties		54,753,444		—		—
Marketing and other deductions		569,842		257,126		110,534
General and administrative expenses		2,770,772		1,211,082		532,035
Total costs and expenses		63,365,767		4,209,974		775,859
Operating (loss) income		(52,474,429)		343,370		(457,549)
Other expense
Interest expense		350,042		60,152		39,307
Net (loss) income	$	(52,824,471)	$	283,218	$	(496,856)
Production Data:
Oil (Bbls)		109,886		59,511		3,696
Natural gas (Mcf)		984,366		489,671		32,961
Natural gas liquids (Bbls)		54,583		20,930		1,220
Combined volumes (Boe) (6:1)		328,530		162,053		10,410

Comparison of the Three Months Ended March 31, 2018 to the Three Months Ended March 31, 2017

The period presented for the three months ended March 31, 2017 includes the results of operations for the period from February 8, 2017 to March 31, 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 three months ended March 31, 2018, our revenues were $11.2 million, an increase of $6.3 million, from $4.9 million for the three months ended March 31, 2017. The increase in revenues was primarily attributable to the full quarter of production from our properties for the three months ended March 31, 2018 compared to the three months ended March 31, 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 three months ended March 31, 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 328,530 Boe or 3,650 Boe/d, for the three months ended March 31, 2018, an increase of 156,067 Boe or 1,734 Boe/d, from 172,463 Boe or 1,916 Boe/d, for the three months

ended March 31, 2017. The increase in production volumes was primarily attributable to the full quarter of production from our properties for the three months ended March 31, 2018 compared to the three months ended March 31, 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 three months ended March 31, 2018 includes the relevant production from those acquired interests.

Our operators received an average of $60.97 per Bbl of oil, $2.69 per Mcf of natural gas and $26.69 per Bbl of NGL for the volumes sold during the three months ended March 31, 2018 and $47.33 per Bbl of oil, $2.60 per Mcf of natural gas and $23.42 per Bbl of NGL for the volumes sold during the three months ended March 31, 2017. The three months ended March 31, 2018 increased 28.8% or $13.64 per Bbl of oil and 3.5% or $0.09 per Mcf of natural gas as compared to the three months ended March 31, 2017. These increases are consistent with prices experienced in the market, specifically when compared to the EIA average price increases of 21.5% or $11.14 per Bbl of oil and 2.3% or $0.07 per Mcf of natural gas for the comparable periods.

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended March 31, 2018 includes $0.2 million of unrealized loss and $0.1 million of realized loss on commodity derivative instruments. We did not have any commodity derivative instruments for the three months ended March 31, 2017.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended March 31, 2018 were $0.8 million, an increase of $0.6 million from $0.2 million for the three months ended March 31, 2017. The increase in production and ad valorem taxes was primarily attributable to the full quarter of production from our properties for the three months ended March 31, 2018 compared to the three months ended March 31, 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 three months ended March 31, 2018 includes the relevant production from those acquired interests.

Depreciation, Depletion and Accretion Expense

Depreciation, depletion and accretion expense for the three months ended March 31, 2018 was $4.5 million, an increase of $1.9 million from $2.6 million for the three months ended March 31, 2017. The increase in the depreciation, depletion and accretion expense was primarily attributable to the full quarter of production from our properties for the three months ended March 31, 2018 compared to the three months ended March 31, 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 three months ended March 31, 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 producing reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $13.43 for the three months ended March 31, 2018, a decrease of $1.93 per barrel from $15.36 average depletion rate per barrel for the three months ended March 31, 2017.

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 three months ended March 31, 2018 as a result of our quarterly full cost ceiling analysis. No impairment expense was recorded for the three months ended March 31, 2017. See “Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor―Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment of oil and natural gas properties for the Partnership for the three months ended March 31, 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 three months ended March 31, 2018 were $0.6 million, an increase of $0.2 million from $0.4 million for the three months ended March 31, 2017. The increase in marketing and other deductions was primarily attributable to the full quarter of production from our properties for the three months ended March 31, 2018 compared to the three months ended March 31, 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 three months ended March 31, 2018 includes the relevant production from those acquired interests.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2018 were $2.8 million, an increase of $1.1 million from $1.7 million for the three months ended March 31, 2017. The increase in general and administrative expenses was attributable to increased costs related to operating as a publicly traded company. The three months ended March 31, 2018 include the Partnership as a whole compared the three months ended March 31, 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 three months ended March 31, 2018 was $0.4 million as compared to interest expense of $0.1 million for the three months ended March 31, 2017. This increase was due to debt incurred to fund acquisitions in 2017.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations and equity and debt financings and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. We have entered into a $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), to initially be used for general partnership purposes, including working capital, acquisitions and certain IPO-related transaction expenses. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million, providing for maximum availability under the secured revolving credit facility of $50.0 million. As of May 4, 2018, we had an outstanding balance of $30.8 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 General Partner’s Board of Directors (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.

Unlike a number of other master limited partnerships, 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, although 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.

On May 2, 2017, the Board of Directors declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The Partnership’s calculated cash available for distribution was $0.18 per common unit for the quarter. However, during the period ended March 31, 2017, pursuant to the contribution agreement entered into by the Contributing Parties prior to the IPO, the Partnership received cash from the Contributing Parties for oil, natural gas and NGL production for periods prior to the IPO. The Board of Directors voted to distribute an additional $0.05 per common unit. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

On April 27, 2018 the Board of Directors declared a quarterly cash distribution of $0.42 per common unit for the quarter ended March 31, 2018. The distribution will be paid on May 14, 2018 to unitholders of record as of the close of business on May 7, 2018.

Cash Flows

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


	Partnership				Predecessor
	Three Months Ended March 31,		Period from February 8, 2017 to March 31,		Period from January 1, 2017 to February 7,
	2018		2017		2017
Cash Flow Data:
Cash flows provided by operating activities	$	7,294,089	$	2,712,193	$	186,719
Cash flows used in investing activities		(21,937)		(98,640,315)		(523)
Cash flows (used in) provided by financing activities		(6,061,123)		99,820,000		—
Net increase in cash	$	1,211,029	$	3,891,878	$	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 three months ended March 31, 2018 were $7.3 million, an increase of $4.4 million compared to $2.9 million for the three months ended March 31, 2017. The increase in cash flows provided by operating activities was primarily attributable to the full quarter of production from our properties for the three months ended March 31, 2018 compared to the three months ended March 31, 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 three months ended March 31, 2018 includes the relevant production and revenues from those acquired interests. To a lesser extent, an increase in the price received for oil and natural gas production also contributed to the increase in cash flow provided by operating activities.

Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2018 decreased by $98.6 million compared to the three months ended March 31, 2017. For the period from February 8, 2017 to March 31, 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 $2.4 million for a deposit on oil and natural gas properties acquired in the second quarter of 2017.

Financing Activities

Cash flows used in financing activities was $6.1 million for the three months ended March 31, 2018 as compared to cash flows provided by financing activities of $99.8 million for the three months ended March 31, 2017. Cash flows used in financing activities for the three months ended March 31, 2018 consists of distributions paid to unitholders. During the period from February 8, 2017 to March 31, 2017, we received $96.2 million in proceeds from our IPO, we borrowed $3.9 million, and paid loan origination costs of $0.3 million.

Capital Expenditures

During the period from February 8, 2017 to March 31, 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 $96.3 million in cash. Additionally, we spent $2.4 million on a deposit on oil and natural gas properties acquired in the second quarter of 2017. 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. Under the secured revolving credit facility, availability under the facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will 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. The secured revolving credit facility permits aggregate commitments under the facility to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0 million.

The secured revolving credit facility 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 May 4, 2018, we have borrowed $30.8 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating Company, LLC and the acquisition of various mineral and royalty interests for an aggregate purchase price of approximately $29.3 million.

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 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

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 March 31, 2018, neither we, nor our Predecessor had any off‑balance sheet arrangements other than operating leases.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparty to the contracts is an unrelated third party.

At March 31, 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.

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 3—Derivatives to the unaudited consolidated financial statements for additional information regarding the Partnership’s commodity derivatives.

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017)
3.2	—	First Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners LP, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Form 8‑K filed on February 14, 2017)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.2 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)
10.1†	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan 2018 Restricted Unit Agreement (incorporated by reference to Exhibit 10.4 to Kimbell Royalty Partners, LP’s Form 10-K file on March 9, 2018)
10.2	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between Duncan Management, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.9 to Kimbell Royalty Partners, LP’s Form 10-K file on March 9, 2018)
10.3	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.11 to Kimbell Royalty Partners, LP’s Form 10-K file on March 9, 2018)
10.4	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2017, by and between Nail Bay Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.13 to Kimbell Royalty Partners, LP’s Form 10-K file on March 9, 2018)
10.5	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between Steward Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.15 to Kimbell Royalty Partners, LP’s Form 10-K file on March 9, 2018)
10.6	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between Taylor Companies Mineral Management, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.17 to Kimbell Royalty Partners, LP’s Form 10-K file on March 9, 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


	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner

Date: May 11, 2018	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: May 11, 2018	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer