Exhibit 99.1

Unaudited Pro Forma Condensed Combined Financial Statements

On July 12, 2018 (the “Closing Date”), Kimbell Royalty Partners, LP, a Delaware limited partnership (“Kimbell” or the “Partnership”), completed its acquisition (the “Acquisition”) of (i) all of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC, a Delaware limited liability company (“Haymaker Minerals”), pursuant to the Securities Purchase Agreement, dated as of May 28, 2018, by and among Kimbell, Haymaker Minerals and Haymaker Services, LLC, a Delaware limited liability company (“Haymaker Services”), and (ii) all of the equity interests in certain subsidiaries, including Haymaker Properties, L.P. (“Haymaker Properties”), owned by Haymaker Resources, LP, a Delaware limited partnership (“Haymaker Resources” and, together with Haymaker Minerals, the “Haymaker Sellers”), pursuant to the Securities Purchase Agreement, dated as of May 28, 2018, by and among Kimbell, Haymaker Resources and Haymaker Services (the “Haymaker Resources Purchase Agreement”). The aggregate consideration for the Acquisition consisted of approximately $216.3 million in cash (including amounts held in escrow, after standard pre-closing adjustments) and the issuance of 10 million common units representing limited partner interests (“Common Units”), resulting in a total valuation of approximately $451.7 million based on a closing price of $23.54 per unit for Kimbell’s Common Units as of the Closing Date. The completion of the Acquisition is referred to herein as the “Haymaker Closing.”  Prior to the Closing Date, EIGF Aggregator III LLC, a Delaware limited liability company, TE Drilling Aggregator LLC, a Delaware limited liability company, and Haymaker Management, LLC, a Texas limited liability company (each of the preceding entities, together with Haymaker Minerals, the “Haymaker Holders”), were designated as the recipients of the portion of the Common Units issued as consideration in connection with the Haymaker Resources Purchase Agreement.

At the time of the Haymaker Closing, Kimbell also entered into an amendment (the “Credit Agreement Amendment”) to Kimbell’s existing Credit Agreement, dated as of January 11, 2017 (the “Original Credit Agreement” and, the Original 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, resulting in a fully underwritten $200 million revolving credit facility.

The Board of Directors of Kimbell Royalty GP, LLC, a Delaware limited liability company and the general partner of the Partnership, approved on July 2, 2018, a change in the Partnership’s U.S. federal income tax status from a “partnership” to a “corporation” by means of a “check-the-box” election (the “Tax Election”).  On September 24, 2018, the Tax Election became effective. Following the Tax Election, the Partnership is treated as an entity taxable as a corporation for U.S. federal income tax purposes and the Partnership will pay entity-level U.S. federal income tax, currently at a flat rate of 21% on its taxable income, if any.

On the day immediately prior to the effectiveness of the Tax Election, (i) the Partnership’s equity interest in Kimbell Royalty Operating, LLC, a Delaware limited liability company (the “Operating Company”), was recapitalized into newly issued common units of the Operating Company (“OpCo Common Units”) and  newly issued Series A Cumulative Convertible Preferred Units of the Operating Company (“OpCo Series A Preferred Units”), (ii) the Haymaker Holders and the Kimbell Art Foundation delivered and assigned to the Partnership the Common Units they owned, in exchange for (a) newly issued Class B common units representing limited partner interests in the Partnership (the “Class B Units”) and (b) newly issued OpCo Common Units (iii) the Limited Liability Company Agreement of the Operating Company was amended and restated to reflect the foregoing transactions and (iv) the Second Amended and Restated Agreement of Limited Partnership of the Partnership was amended and restated to reflect the foregoing transactions (together with the Tax Election, the “Up-C Transaction”).  The Partnership pays U.S. federal income tax on income allocated from its ownership of OpCo Common Units and OpCo Series A Preferred Units.  There was no step-up in tax basis on OpCo Common Units or OpCo Series A Preferred Units as a result of the Up-C Transaction, and no tax receivable agreement was entered into between the Partnership and the Haymaker Holders and the Kimbell Art Foundation. The Acquisition, the Credit Agreement Amendment and the Up-C Transaction are collectively referred to herein as the “Pro Forma Transactions.”

The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018 has been prepared to reflect the Pro Forma Transactions. The pro forma financial data is presented as if the Pro Forma Transactions had occurred on January 1, 2018.

The unaudited pro forma adjustments are based on preliminary estimates, accounting judgments and currently available information and assumptions that management believes are reasonable. The notes to the unaudited pro forma

condensed combined statement of operations provide a detailed discussion of how such adjustments were derived and presented in the unaudited pro forma financial information.

The unaudited pro forma condensed combined financial information has been prepared to reflect adjustments to the Partnership’s historical financial information that are (i) directly attributable to the Pro Forma Transactions and (ii) factually supportable, and with respect to the unaudited pro forma condensed combined statement of operations, expected to have a continuing impact on the Partnership’s results.

The unaudited pro forma condensed combined statement of operations is for informational purposes only and does not purport to represent what the Partnership’s financial position and results of operations would have been had the Acquisition occurred on the dates indicated. This unaudited pro forma condensed combined financial information should not be used to project the Partnership’s financial performance for any future period. A number of factors may affect the Partnership’s results. Please read “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “Form 10-K”) for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in the Partnership’s business.

The unaudited pro forma condensed combined financial information should be read in conjunction with the audited consolidated financial statements and notes thereto contained in the Form 10-K and each of the historical financial statements and notes thereto of each of Haymaker Minerals and Haymaker Properties, as filed in Amendment No. 1 to the Current Report on Form 8-K filed by the Partnership with the Securities and Exchange Commission on July 18, 2018.

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2018

	Kimbell			Haymaker Properties			Haymaker Minerals							Pro Forma
	Year Ended December 31, 2018			Period from January 1, 2018 to July 12, 2018 (Acquisition Date)			Period from January 1, 2018 to July 12, 2018 (Acquisition Date)			Pro Forma Adjustments				Year Ended December 31, 2018
Oil, natural gas and NGL revenues	$	65,713,112		$	—		$	—		$	23,667,490		(C)	$	88,226,707
										(368,124		)	(E)
										(785,771		)	(D)
Crude oil and condensate sales	—			3,152,933			6,048,098			(9,201,031		)	(C)	—
Natural gas sales	—			10,577,782			1,351,999			(11,929,781		)	(C)	—
Natural gas liquids sales and other	—			1,581,258			955,420			(2,536,678		)	(C)	—
Income from lease bonus	1,213,550			259,445			1,119,041			368,124			(E)	2,960,160
Gain on commodity derivative instruments	3,331,548			—			—			—				3,331,548
Total revenues	70,258,210			15,571,418			9,474,558			(785,771		)		94,518,415
Costs and expenses
Production and ad valorem taxes	4,399,667			—			—			1,334,976			(F)	5,734,643
Production ad valorem, and withholding taxes	—			778,482			656,765			(1,334,976		)	(F)	—
										(100,271		)	(D)
Production expense	—			1,815,625			630,618			(2,431,650		)	(G)	—
										(14,593		)	(D)
Depreciation, depletion and accretion expense	25,213,043			3,971,571			2,534,303			(6,505,874		)	(A)	33,960,015
										8,746,972			(A)
Impairment of oil and natural gas properties	67,311,501			—			—			—				67,311,501
Marketing and other deductions	4,652,313			—			—			2,431,650			(G)	7,083,963
General and administrative expense	16,847,328			4,834,483			3,281,048			(5,458,064		)	(I)	19,504,795
Total costs and expenses	118,423,852			11,400,161			7,102,734			(3,331,830		)		133,594,917
Operating (loss) income	(48,165,642		)	4,171,257			2,371,824			2,546,059				(39,076,502		)
Other income (expense)
(Loss) gain on derivatives	—			(736,696		)	(632,594		)	1,369,290			(H)	—
Interest expense	(4,091,900		)	(538,704		)	(398,643		)	5,029,247			(B)	(5,813,652		)
										(5,813,652		)	(B)
Other income	—			4,686			17,710			(22,396		)	(J)	—
Total other income (expense)	(4,091,900		)	(1,270,714		)	(1,013,527		)	562,489				(5,813,652		)
(Loss) income before income taxes	(52,257,542		)	2,900,543			1,358,297			3,108,548				(44,890,154		)
Income tax benefit	—			—			566			—				566
Provision for income taxes	(24,681		)	—			—			—				(24,681		)
Net (loss) income before Series A preferred unit distribution and accretion	(52,282,223		)	2,900,543			1,358,863			3,108,548				(44,914,269		)
Distribution and accretion on Series A preferred units	(6,310,040		)	—			—			—				(6,310,040		)
Net (loss) income	(58,592,263		)	2,900,543			1,358,863			3,108,548				(51,224,309		)
Net loss attributable to noncontrolling interests	(1,855,681		)	—			—			—				(1,855,681		)
Net (loss) income attributable to Kimbell Royalty Partners LP	(56,736,582		)	2,900,543			1,358,863			3,108,548				(49,368,628		)
Distribution on Class B units	(30,967		)	—			—			—				(30,967		)
Net (loss) income attributable to common units	$	(56,767,549	)	$	2,900,543		$	1,358,863		$	3,108,548			$	(49,399,595	)
Net loss attributable to common units
Basic	$	(3.08	)											$	(1.74	)
Diluted	$	(3.08	)											$	(1.74	)
Weighted average number of common units outstanding
Basic	18,442,234									10,000,000				28,442,234
Diluted	18,442,234									10,000,000				28,442,234
Distributions declared and paid per Common Unit	$	1.70												$	1.70

For the Year Ended December 31, 2018

1) Basis of Presentation

The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018 is derived from the historical financial statements of Kimbell, Haymaker Minerals and Haymaker Properties.

2) Pro Forma Adjustments and Assumptions

The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual effects of the Pro Forma Transactions will differ from the pro forma adjustments. A general description of the pro forma adjustments is provided as follows:

A)To eliminate the historical depreciation, depletion and accretion expense related to the acquired oil and natural gas properties.

B)Reflects the Partnership’s entrance into the Credit Agreement Amendment, and increased borrowings at the closing of the Acquisition of $105.0 million.

The Amended Credit Agreement bears interest at LIBOR plus a margin of 2.5%.  The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018 used an estimated 4.62% interest rate on the outstanding borrowings under the Amended Credit Facility.  The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2018 estimated that the Partnership had total borrowings outstanding under the Amended Credit Agreement of $87.3 million. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense of approximately $0.9 million annually, assuming that the Partnership’s indebtedness remained constant throughout the year.

The following table represents the impact of adjustments to interest expense:

	Year Ended
	December 31,
	2018
New secured revolving credit facility:
Interest expense	$	5,322,365
Amortization expense of loan origination costs	491,287
	5,813,652
Pro forma adjustment of existing debt:
Interest expense - Kimbell	(4,091,900		)
Interest expense - Haymaker Properties	(538,704		)
Interest expense - Haymaker Minerals	(398,643		)
	(5,029,247		)
Net adjustment to interest expense	$	784,405

C)Reflects the historical statement of operations related to the Acquisition, which also reflects a reclassification of approximately $23.7 million for the year ended December 31, 2018 related to crude oil and condensate sales, natural gas sales, and natural gas liquids (“NGL”) sales and other in order to conform the presentation to be consistent with the Partnership’s presentation of such revenues within the oil, natural gas and NGL revenues line item in its historical statements of operations for the same periods.

D)Haymaker Minerals and Haymaker Properties sold assets to third parties prior to the Haymaker Closing.  This pro forma adjustment reflects the reduction in revenues and direct expenses related to assets that were not acquired by the Partnership but that were included in the historical statements of operations of Haymaker Minerals and Haymaker Properties.

E)Reflects the reclassification of revenue related to lease bonus income that was previously recorded in the Partnership’s oil, natural gas and NGL revenues.

F)Reflects the reclassification of production, ad valorem, and withholding taxes into production and ad valorem taxes.

G)Reflects the reclassification of production expense into marketing and other deductions.

H)Reflects the elimination of the impact of Haymaker Minerals’ and Haymaker Properties’ derivative instruments, which were terminated prior to the Haymaker Closing, from their respective historical statement of operations.

I)For the year ended December 31, 2018, Haymaker Minerals and Haymaker Properties incurred $2.2 million and $3.3 million, respectively, in transaction costs related to their divestiture to Kimbell.  This proforma adjustment reflects the reduction in general and administrative expenses related to the historical statement of operations of Haymaker Minerals and Haymaker Properties.

J)Reflects the elimination of other income from Haymaker Minerals’ and Haymaker Properties’ historical statement of operations related to revenues that are not considered to be ongoing.

3) Pro Forma Net Income (Loss) per Common Unit

Pro forma net income (loss) per Common Unit is determined by dividing the pro forma net income (loss) available to common unitholders by the number of Common Units reflected in the unaudited condensed combined pro forma financial statements. All Common Units were assumed to have been outstanding since the beginning of the periods presented.  The calculation of diluted net loss per Common Unit for the year ended December 31, 2018 excludes 1,157,924 non-vested, restricted Common Units issuable upon vesting and 5,945,946 additional Common Units, which represent the Series A Preferred Units on an as-converted basis, because their inclusion in the calculation would be anti-dilutive.

4) Pro Forma Supplemental Oil and Gas Reserve Information

The Partnership has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Partnership’s audited consolidated statements of operations included in the Form 10-K for information about results of the Partnership’s operations for oil and gas producing activities.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

	December 31,
	2018
Oil, natural gas and NGL interests
Proved properties	$	538,290,590
Unevaluated properties	280,304,353
Total oil, natural gas and NGL interests	818,594,943
Accumulated depreciation, depletion, accretion and impairment	(107,779,453		)
Net oil, natural gas and NGL interests capitalized	$	710,815,490

Costs incurred in oil and natural gas activities

Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows:

	Year Ended December 31,
	2018
Acquisition costs
Proved properties	$	243,227,632
Unevaluated properties	288,334,110
Total	531,561,742
Development costs
Proved properties	—
Total	—
Total costs incurred on oil, natural gas and NGL activities	$	531,561,742

Results of Operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and NGL operations.

	Year Ended December 31,
	2018
Oil, natural gas and NGL revenues	$	65,713,112
Lease bonus and other income	1,213,550
Production and ad valorem taxes	(4,399,667		)
Depreciation, depletion and accretion expense	(25,213,043		)
Impairment of oil and natural gas properties	(67,311,501		)
Marketing and other deductions	(4,652,313		)
Results of operations from oil, natural gas and NGLs	$	(34,649,862	)

The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves, and the estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2018 and 2017. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC.

Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

A Boe conversion ratio of six thousand cubic feet per barrel (6mcf/Bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

The Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below:

	Crude Oil and				Natural Gas
	Condensate		Natural Gas		Liquids		Total
	(MBbls)		(MMcf)		(MBbls)		(MBOE)
Net proved reserves at December 31, 2017	7,463		63,916		2,838		20,954
Revisions of previous estimates (1)	194		1,754		952		1,437
Purchase of minerals in place (2)	3,729		69,465		2,166		17,473
Production	(591	)	(7,874	)	(310	)	(2,213	)
Net proved reserves at December 31, 2018	10,795		127,261		5,646		37,651
Net Proved Developed Reserves
December 31, 2017	5,284		47,501		2,202		15,403
December 31, 2018	9,183		116,321		5,063		33,633
Net Proved Undeveloped Reserves
December 31, 2017	2,179		16,415		636		5,551
December 31, 2018	1,612		10,940		583		4,018

(1)Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

(2)Includes the acquisition of two packages of diverse mineral and royalty interests for a total of $243.2 million. The first acquisition totaling $155.7 million consists of mineral and royalty interests primarily in the Permian Basin, Haynesville Shale, Mid-Continent Area and Appalachia Region. The second acquisition totaling $87.5 million consists of mineral and royalty interests primarily in the Permian Basin, Eagle Ford Shale and Appalachia Region.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Standardized Measure

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the properties is as follows (in thousands):

	Year Ended  December 31,
	2018
Future cash inflows	$	1,056,464
Future production costs	(79,724		)
Future state margin taxes	(32,885		)
Future income tax expense	(41,241		)
Future net cash flows	902,614
Less 10% annual discount to reflect timing of cash flows	(504,247		)
Standard measure of discounted future net cash flows	$	398,367

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2018 were $65.56 per barrel for crude oil and $3.10 per Mcf for natural gas, respectively.

Future production costs are computed primarily by the Partnership’s petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands):

	Year Ended  December 31,
	2018
Standardized measure - beginning of year	$	215,552
Sales, net of production costs	(56,661		)
Net changes of prices and production costs related to future production	11,355
Extensions, discoveries and improved recovery, net of future production costs	—
Revisions of previous quantity estimates, net of related costs	16,385
Net changes in state margin taxes	(13,271		)
Net changes in income taxes	(17,232		)
Accretion of discount	21,555
Purchases of reserves in place	175,885
Timing differences and other	44,799
Standardized measure - end of year	$	398,367