Kimbell Royalty Partners (KRP) 10-K 27 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Feb. 21, 2020	Jun. 30, 2019
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Entity Registrant Name	Kimbell Royalty Partners, LP
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 344.8
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Ex Transition Period	true
Entity Shell Company	false
Entity Central Index Key	0001657788
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Common Units
Entity Common Stock, Shares Outstanding		33,432,211
Class B
Entity Common Stock, Shares Outstanding		20,644,047

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 14,204,250	$ 15,773,987
Oil, natural gas and NGL receivables	19,170,762	18,809,170
Commodity derivative assets	687,933	2,981,117
Accounts receivable and other current assets	76,868	50,551
Total current assets	34,139,813	37,614,825
Property and equipment, net	1,327,057	429,602
Investment in affiliate (equity method)	2,952,264
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($275,041,784 and $280,304,353 excluded from depletion at December 31, 2019 and December 31, 2018, respectively)	1,033,355,017	818,594,943
Less: accumulated depreciation, depletion and impairment	(328,913,425)	(107,779,453)
Total oil and natural gas properties, net	704,441,592	710,815,490
Right-of-use assets, net	3,399,634
Commodity derivative assets	116,568	1,246,829
Loan origination costs, net	2,217,126	3,178,627
Total assets	748,594,054	753,285,373
Current liabilities
Accounts payable	1,207,736	1,331,081
Other current liabilities	4,231,579	2,468,945
Total current liabilities	5,439,315	3,800,026
Operating lease liabilities, excluding current portion	3,124,416
Long-term debt	100,135,477	87,309,544
Total liabilities	108,699,208	91,109,570
Commitments and contingencies (Note 15)
Mezzanine equity:
Series A preferred units (110,000 units issued and outstanding as of December 31, 2019 and December 31, 2018)	74,909,732	69,449,006
Unitholders' equity:
Common units (23,518,652 units issued and outstanding as of December 31, 2019 and 18,056,487 units issued and outstanding as of December 31, 2018)	282,549,841	299,821,901
Class B units (25,557,606 units issued and outstanding as of December 31, 2019 and 19,453,258 units issued and outstanding as of December 31, 2018)	1,277,880	972,663
Total unitholders' equity	283,827,721	300,794,564
Noncontrolling interest	281,157,393	291,932,233
Total equity	564,985,114	592,726,797
Total liabilities, mezzanine equity and unitholders' equity	$ 748,594,054	$ 753,285,373

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
CONSOLIDATED BALANCE SHEETS
Oil and natural gas properties excluded from depletion	$ 275,041,784	$ 280,304,353
Temporary equity, issued (in units)	110,000	110,000
Temporary equity, outstanding (in units)	110,000	110,000
Common units, issued (in units)	23,518,652	18,056,487
Common units, outstanding (in units)	23,518,652	18,056,487
Class B units, issued (in units)	25,557,606	19,453,258
Class B units, outstanding (in units)	25,557,606	19,453,258

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
(Loss) gain on commodity derivative instruments, net		$ (318,829)	$ (1,732,321)	$ 3,331,548
Total revenues	$ 318,310	30,346,263	108,225,270	70,258,210
Costs and expenses
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor
Production and ad valorem taxes	$ 19,651	2,452,058	7,719,949	4,399,667
Depreciation and depletion expense	113,639	15,546,341	52,118,367	25,213,043
Impairment of oil and natural gas properties	0	0	169,150,255	67,311,501
Marketing and other deductions	110,534	1,648,895	8,145,397	4,652,313
General and administrative expense	532,035	8,191,792	22,666,601	16,847,328
Total costs and expenses	775,859	27,839,086	259,800,569	118,423,852
Operating (loss) income	(457,549)	2,507,177	(151,575,299)	(48,165,642)
Other income (expense)
Equity income in affiliate			80,481
Interest expense	(39,307)	(791,437)	(5,813,702)	(4,091,900)
Net (loss) income before income taxes	(496,856)	1,715,740	(157,308,520)	(52,257,542)
Provision for income taxes			899,425	24,681
Net (loss) income	(496,856)	1,715,740	(158,207,945)	(52,282,223)
Distribution and accretion on Series A preferred units			(13,878,336)	(6,310,040)
Net loss and distributions and accretion on Series A preferred units attributable to noncontrolling interests			89,148,428	1,855,681
Distribution on Class B units			(94,429)	(30,967)
Net (loss) income attributable to common units	$ (496,856)	$ 1,715,740	$ (83,032,282)	$ (56,767,549)
Net (loss) income attributable to common units
Net loss attributable to common units per unit (basic) (in dollar per share)		$ 0.11	$ (3.92)	$ (3.08)
Net loss attributable to common units per unit (diluted) (in dollar per share)		$ 0.10	$ (3.92)	$ (3.08)
Net loss income attributable to common units per unit (basic) (in dollar per share)	$ (0.82)
Net loss income attributable to common units per unit (diluted) (in dollar per share)	$ (0.82)
Weighted average number of common units outstanding
Weighted average number of common units outstanding Basic (in units)		16,336,871	21,192,714	18,442,234
Weighted average number of common units outstanding Diluted (in units)		16,455,602	21,192,714	18,442,234
Weighted average number of common units outstanding Basic (in units)	604,137
Weighted average number of common units outstanding Diluted (in units)	604,137
Oil, natural gas and NGL revenues
Revenue	$ 318,310	$ 29,943,920	$ 107,480,446	$ 65,713,112
Lease bonus and other income
Revenue		$ 721,172	$ 2,477,145	$ 1,213,550

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY AND PREDECESSOR MEMBERS' EQUITY - USD ($)	Common Units	Class B Common Units	Non Controlling Interest	Total
Financial Designation, Predecessor and Successor				Predecessor
Unitholders' capital, beginning balance at Dec. 31, 2016				$ 8,631,862
Unitholders' capital, beginning balance at Dec. 31, 2016	$ 8,631,862
Unitholders' capital, beginning balance (in units) at Dec. 31, 2016	604,137
Increase (Decrease) in Unitholders' Capital
Unit-based compensation	$ 50,422			50,422
Net (loss) income	(496,856)			(496,856)
Transfer of membership units to Rivercrest Royalties Holdings, LLC	$ (98,988)			(98,988)
Transfer of membership units to Rivercrest Royalties Holdings, LLC (in units)	(604,137)
Unitholders' capital, ending balance at Feb. 07, 2017	$ 8,086,440			8,086,440
Increase (Decrease) in Unitholders' Capital
Common units issued to Predecessor in exchange for oil and natural gas properties (in units)	1,191,974
Units issued for Acquisition	$ 169,033,212			169,033,212
Units issued for Acquisition (in units)	9,390,734
Common units issued	$ 103,500,000			103,500,000
Common units issued (in units)	5,750,000
Underwriting discount and structuring fee incurred at initial public offering	$ (7,245,000)			(7,245,000)
Unit-based compensation	$ 798,413			798,413
Unit-based compensation (in units)	177,091
Distributions to unitholders	$ (13,823,371)			(13,823,371)
Net (loss) income	1,715,740			1,715,740
Unitholders' capital, ending balance at Dec. 31, 2017	$ 262,065,434			262,065,434
Unitholders' capital, ending balance (in units) at Dec. 31, 2017	16,509,799
Increase (Decrease) in Unitholders' Capital
Recapitalization related to tax conversion	$ (209,591,880)	$ 647,663	$ 209,591,880	647,663
Recapitalization related to tax conversion (in units)	(12,953,258)	12,953,258
Common units issued	$ 61,411,708			61,411,708
Common units issued (in units)	3,450,000
Conversion of Class B units to common units		$ 325,000	90,025,000	90,350,000
Conversion of Class B units to common units (in units)		6,500,000
Common units issued for Haymaker Acquisition	$ 235,400,000			235,400,000
Common units issued for Haymaker Acquisition (in units)	10,000,000
Unit-based compensation	$ 3,170,299			3,170,299
Unit-based compensation (in units)	1,049,946
Distributions to unitholders	$ (32,474,077)		(5,828,966)	(38,303,043)
Issuance of Series A preferred units	36,607,966			36,607,966
Distribution and accretion on Series A preferred units	(4,510,648)		(1,799,392)	(6,310,040)
Distribution on Class B units	(30,967)			(30,967)
Net (loss) income	(52,225,934)		(56,289)	(52,282,223)
Unitholders' capital, ending balance at Dec. 31, 2018	$ 299,821,901	$ 972,663	291,932,233	$ 592,726,797
Unitholders' capital, ending balance (in units) at Dec. 31, 2018	18,056,487	19,453,258		18,056,487
Increase (Decrease) in Unitholders' Capital
Unit-based compensation	$ 7,502,678			$ 7,502,678
Restricted units used for tax withholding	$ (46,280)			(46,280)
Restricted units used for tax withholding (in units)	(2,835)
Conversion of Class B units to common units	$ 93,688,489	$ (273,250)	(93,688,489)	(273,250)
Conversion of Class B units to common units (in units)	5,465,000	(5,465,000)
Class B units issued for acquisition		$ 578,467	207,734,725	208,313,192
Class B units issued for acquisition (in units)		11,569,348
Distributions to unitholders	$ (35,384,665)		(35,672,648)	(71,057,313)
Distribution and accretion on Series A preferred units	(6,552,484)		(7,325,852)	(13,878,336)
Distribution on Class B units	(94,429)			(94,429)
Net (loss) income	(76,385,369)		(81,822,576)	(158,207,945)
Unitholders' capital, ending balance at Dec. 31, 2019	$ 282,549,841	$ 1,277,880	$ 281,157,393	$ 564,985,114
Unitholders' capital, ending balance (in units) at Dec. 31, 2019	23,518,652	25,557,606		23,518,652

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$ (496,856)	$ 1,715,740	$ (158,207,945)	$ (52,282,223)
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and depletion expense	$ 113,639	15,546,341	52,118,367	25,213,043
Impairment of oil and natural gas properties	0	0	169,150,255	67,311,501
Amortization of right-of-use assets			154,525
Amortization of loan origination costs	4,241	57,292	1,050,278	466,002
Amortization of tenant improvement allowance	(2,864)
Equity income in affiliate			(80,481)
Unit-based compensation	50,422	798,413	7,502,678	3,170,299
Loss (gain) on commodity derivative instruments, net of settlements		318,829	3,423,445	(4,546,775)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables	14,551	(1,689,609)	4,410,140	(7,041,371)
Accounts receivable and other current assets	333,056	(236,673)	(26,317)	186,122
Accounts payable	247,972	316,486	(125,387)	985,936
Other current liabilities	(77,442)	1,746,662	1,762,633	(259,554)
Operating lease liabilities			(429,743)
Net cash provided by operating activities	186,719	18,573,481	80,702,448	33,202,980
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(61,932)	(1,032,105)	(403,699)
Proceeds from sale of oil and natural gas properties				10,576,595
Purchase of oil and natural gas properties	(523)	(125,848,776)	(11,686,570)	(211,101,058)
Investment in affiliate			(2,965,933)
Cash distribution from equity method investee			94,150
Net cash used in investing activities	(523)	(125,910,708)	(15,590,458)	(200,928,162)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of Series A preferred units, net of issuance costs				103,359,603
Proceeds from equity offering				61,411,708
Proceeds from initial public offering		96,255,000
Contributions from Class B unitholders			470,000	972,663
Redemption of Class B contributions on converted units			(273,250)
Issuance costs paid on Series A preferred units			(717,612)
Distributions to common unitholders		(13,823,371)	(35,384,665)	(38,303,043)
Distribution to OpCo unitholders			(35,672,648)
Distributions on Series A preferred units			(7,700,000)	(2,630,834)
Distributions to Class B unitholders			(94,429)	(12,953)
Borrowings on long-term debt		30,843,593	12,825,933	124,336,547
Repayments on long-term debt				(67,870,596)
Payment of loan origination costs		(312,500)	(88,777)	(3,389,421)
Restricted units used for tax withholding			(46,279)
Net cash (used in) provided by financing activities		112,962,722	(66,681,727)	177,873,674
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	186,196	5,625,495	(1,569,737)	10,148,492
CASH AND CASH EQUIVALENTS, beginning of period	505,880	692,076	15,773,987	5,625,495
CASH AND CASH EQUIVALENTS, end of period	692,076	5,625,495	14,204,250	15,773,987
Supplemental cash flow information:
Cash paid for interest	34,505	$ 455,228	5,181,650	3,285,387
Cash paid for taxes	$ 5,355		801,669
Non-cash investing and financing activities:
Right-of-use assets obtained in exchange for operating lease liabilities			3,554,159
Units issued in exchange for oil and natural gas properties			207,843,194	325,425,000
Distribution to Series A preferred unitholders in accounts payable			981,837	981,837
Non-cash deemed distribution to Series A preferred units			6,178,336	2,697,369
Distribution to Class B unitholders in accounts payable				18,014
Oil and natural gas property acquisition costs in accounts payable			$ 2,042
Capital expenditures and consideration payable included in accounts payable and other liabilities				$ 10,645

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2019
ORGANIZATION AND BASIS OF PRESENTATION
ORGANIZATION AND BASIS OF PRESENTATION	Unless the context otherwise requi On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of common units representing limited partner interests. The mineral and royalty interests comprising the Partnership’s initial assets were contributed to it by the Contributing Parties at the closing of its IPO. 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 periods on or prior to February 7, 2017 refers only to the Partnership’s Predecessor for accounting and financial reporting purposes and does not include the results of the Partnership as a whole. At the time of the Partnership’s IPO, the interests underlying the oil, natural gas and natural gas liquids (“NGL”) production revenues of the Partnership’s Predecessor represented 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. NOTE 1—ORGANIZATION Organization Kimbell Royalty Partners, LP is a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest. Basis of Presentation The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (‘‘GAAP’’). A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows. 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. Restructuring, Tax Election and Related Transactions On July 24, 2018, the Partnership entered into a Recapitalization Agreement with Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC (collectively, the “Haymaker Holders”), the Kimbell Art Foundation, Haymaker Resources, LP, the General Partner and the Operating Company pursuant to which (a) the Partnership’s equity interest in the Operating Company was recapitalized into 13,886,204 newly issued common units of the Operating Company (“OpCo common units”) and 110,000 newly issued Series A Cumulative Convertible Preferred Units (“Series A preferred units”) in the Operating Company and (b) the 10,000,000 and 2,953,258 common units held by the Haymaker Holders and the Kimbell Art Foundation, respectively, were exchanged for (i) 10,000,000 and 2,953,258 newly issued Class B common units representing limited partner interests of the Partnership (“Class B units”), respectively, and (ii) 10,000,000 and 2,953,258 newly issued OpCo common units, respectively. The Class B units and OpCo common units are exchangeable together into an equal number of common units representing limited partner interests in the Partnership (“common units”) . In May 2018, the General Partner’s Board of Directors (the “Board of Directors”) unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election (the “Tax Election”). The Tax Election became effective on September 24, 2018. For each Class B unit issued, five cents has been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B units are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units (as defined in Note 7—Long- Term Debt) but prior to distributions on the common units. Following the effectiveness of the Tax Election and the completion of the related transactions, the Partnership’s royalty and minerals business continues to be conducted through the Operating Company, which is taxed as a partnership for federal and state income tax purposes. The Operating Company passes income to the noncontrolling interest and the Partnership, which is treated as a corporation for federal and state income tax purposes. As of February 21, 2020, 61.8% of the OpCo common units were held by the Partnership and 38.2% were held by third parties.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Management Estimates The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, valuation of commodity derivative financial instruments and equity‑based compensation. The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion. Reclassification of Prior Period Presentation Certain prior period amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on previously reported net income (loss), total cash flows from operations or working capital. Cash and Cash Equivalents The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents. Accounts Receivable Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. The Partnership estimates and records an allowance for doubtful accounts when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2019, and 2018, no allowance for doubtful accounts is deemed necessary based upon a review of current receivables and the lack of historical write offs. Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statement of operations within loss on commodity derivative instruments. Property and Equipment Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease. Oil and Natural Gas Properties The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within five years. While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12‑month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO and were excluded from the from the ceiling test calculation pursuant to an exemption from the United States Securities and Exchange Commission (“SEC”), which remained effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that the Partnership was 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. No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). The Partnership recorded an impairment on its oil and natural gas properties of $169.2 million during the year ended December 31, 2019, as a result of its quarterly full cost ceiling analysis and a decline in the 12-month average price of oil and natural gas. The Partnership recorded an impairment expense on its oil and natural gas properties of $67.3 million during the year ended December 31, 2018. Of this amount, an impairment expense of $54.8 million was recorded as a result of the Partnership’s quarterly full-cost ceiling analysis for the three months ended March 31, 2018 following the expiration of the aforementioned exemption and an impairment expense of $12.6 million was recorded for the three months ended December 31, 2018 as a result of the Dropdown (as defined in Note 3—Acquisitions and Divestitures) purchase price exceeding the value of the proved developed reserves added to the full-cost ceiling. As the Partnership does not have the history with its more recent acquisitions made since the IPO and given the non-operating nature of our interests, it can no longer accurately predict the timing of additional drilling. Thus, the Partnership does not intend to book proved undeveloped (“PUD”) reserves going forward. Accordingly, additional impairment charges could be recorded in connection with future acquisitions. While drilling continues to occur on the Partnership’s properties, without the recognition of PUD reserves since the IPO, additional impairments may be required particularly when oil, natural gas, and NGL prices decline. The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2019 or December 31, 2018, the period from February 8, 2017 to December 31, 2017 or the Predecessor 2017 Period. Due to the nature of the Partnership’s and the Predecessor’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2019 or December 31, 2018, the period from February 8, 2017 to December 31, 2017 or the Predecessor 2017 Period. Other Current Liabilities Other current liabilities consist primarily of Series A preferred unit and Class B unit distributions, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short term operating lease liabilities. Income Taxes As discussed further in Note 1—Organization and Basis of Presentation, on May 28, 2018, the Partnership announced that the Board of Directors had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership incurred de minimis amounts of income taxes during the years ended December 31, 2019 and 2018. Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership had no uncertain tax positions at December 31, 2019 and 2018. The Partnership and Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2019 and December 31, 2018, the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions. The Partnership has filed all tax returns to date that are currently due. For the Predecessor, tax years after December 31, 2014 remain subject to possible examination by taxing authorities although no such examination has been requested. Concentration of Credit Risk The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations. At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits. During the year ended December 31, 2019, the Partnership’s top purchaser accounted for approximately 6.0% of oil, natural gas and NGL sales revenue. During the year ended December 31, 2018, the Partnership’s top purchaser accounted for approximately 10% of oil, natural gas and NGL sales revenue. During the period from February 8, 2017 to December 31, 2017, one purchaser accounted for approximately 14% of oil, natural gas and NGL sales revenue. Revenue from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index. Royalty income from oil, natural gas and NGL sales The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and NGLs. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s royalty income contracts. Contract balances Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606 . Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for one to four months after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and NGL contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded. 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. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements. New Accounting Pronouncements Recently Adopted Pronouncements In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016‑02, “Leases.” ASU 2016‑02 requires the recognition of right-of-use (“ROU”) assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year, with early adoption permitted. The Partnership adopted this update using the modified retrospective approach, effective January 1, 2019. The adoption of this update did not have a material impact on the Partnership’s results of operations for the year ended December 31, 2019. The Partnership evaluated whether its contractual arrangements contain leases at the inception of such arrangements. Specifically, the Partnership considered whether it can control the underlying asset and have the right to obtain substantially all of the economic benefits or outputs from the asset. Substantially all of the Partnerships leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s ROU operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying consolidated balance sheet as of December 31, 2019. Current operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of December 31, 2019 was 9.34 years. Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the Amended Credit Agreement, as defined in Note 7—Long-Term Debt, as of January 1, 2019. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the year ended December 31, 2019. Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2019. The total operating lease expense recorded for the year ended December 31, 2019 was approximately $0.3 million. Currently, the most substantial contractual arrangement that the Partnership has classified as an operating lease is the main office space used for operations. In July 2019, the Partnership became the lessee in several other related lease agreements for additional office space. In addition, the Partnership was involved in the construction and design of the underlying assets. The underlying assets were capitalized in July 2019 upon commencement of the lease. Future minimum lease commitments as of December 31, 2019 were as follows: Total 2020 2021 2022 2023 2024 Thereafter Operating leases $ 4,622,449 $ 474,334 $ 478,428 $ 478,837 $ 480,579 $ 486,323 $ 2,223,948 Less: Imputed Interest (1,243,903) Total $ 3,378,546 In July 2018, the FASB issued ASU 2018-09, “Codification Improvements.” This update provides clarification and corrects unintended application of the guidance in various sections. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations for the year ended December 31, 2019. In July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842, Leases.” This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations for the year ended December 31, 2019. Accounting Pronouncements Not Yet Adopted In August 2018, the FASB issued ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement.” This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. The FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments,” which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for the interim and annual periods beginning after December 31, 2018, and will be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Partnership does not plan to early adopt and is currently evaluating the effect the guidance will have on its consolidated financial statements; however, the impact is not expected to be material. In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740) Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

ACQUISITIONS, JOINT VENTURES AN

ACQUISITIONS, JOINT VENTURES AND DIVESTITURES	12 Months Ended
	Dec. 31, 2019
ACQUISITIONS, JOINT VENTURES AND DIVESTITURES
ACQUISITIONS, JOINT VENTURES AND DIVESTITURES	NOTE 3—ACQUISITIONS, JOINT VENTURES AND DIVESTITURES 2019 Activity On March 25, 2019, the Partnership completed the acquisition of all of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC that own oil and natural gas mineral and royalty interests (the “Phillips Acquisition”). The aggregate consideration for the Phillips Acquisition consisted of 9,400,000 OpCo common units and an equal number of Class B units. The assets acquired in the Phillips Acquisition consisted of approximately 866,528 gross acres and 12,210 net royalty acres. On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed $15.0 million. The Joint Venture will be managed by Springbok Operating Company, LLC. The purpose of the Joint Venture will be to make direct or indirect investments in royalty, mineral and overriding royalty interests and similar non-cost bearing interests in oil and gas properties, excluding leasehold or working interests. The Partnership will utilize the equity method of accounting for its investment in the Joint Venture. As of December 31, 2019, the Partnership has paid approximately $3.0 million under its capital commitment. On November 6, 2019, the Partnership acquired various mineral and royalty interests in Oklahoma for an aggregate purchase price of approximately $9.9 million. The Partnership funded the payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired consist of approximately 279,680 gross acres and 186 net royalty acres. On December 12, 2019, the Partnership completed the acquisition of certain mineral and royalty assets (the “Buckhorn Acquisition) from certain affiliates of Buckhorn Resources GP, LLC (collectively, the “Buckhorn Sellers”). The aggregate consideration for the Buckhorn Acquisition consisted of 2,169,348 OpCo common units and an equal number of Class B units. The assets acquired in the Buckhorn Acquisition consisted of approximately 86,005 gross acres and 405 net royalty acres. 2018 Activity In May 2018, the Partnership executed two purchase and sale agreements to sell a small portion of its Delaware Basin acreage for $10.6 million, which was recorded as a reduction in the full-cost pool, with no gain or loss recorded on the sale. At the time of the divestiture, the sales represented approximately 29 barrels of equivalent (“Boe”) per day of production, less than 0.8% of total production and 59 net royalty acres, approximately 0.08% of total net royalty acres. On July 12, 2018, the Partnership completed the acquisition of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (the “Haymaker Acquisition”) in a transaction valued at approximately $444.0 million. The purchase price for the Haymaker Acquisition was comprised of (i) net cash consideration of approximately $208.6 million and (ii) 10,000,000 common units of the Partnership. The Partnership funded the Cash Consideration with borrowings under the Amended Credit Agreement and net proceeds from the Preferred Unit Transaction (as defined in Note 8 — Preferred Units). The assets acquired in the Haymaker Acquisition consist of approximately 5.4 million gross acres and 43,000 net royalty acres. On December 20, 2018, the Partnership completed the acquisition (the “Dropdown”) of (i) certain overriding royalty, royalty and other mineral interests from Rivercrest Capital Partners LP, the Kimbell Art Foundation, and Cupola Royalty Direct, LLC, as well as all of the interests of a subsidiary of Rivercrest Royalties Holdings II, LLC in exchange for a total of 6,500,000 OpCo common units and an equal number of Class B units. The assets acquired in the Dropdown consist of approximately 1.0 million gross acres and 16,700 net royalty acres. 2017 Activity In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres, for an aggregate purchase price of approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility. On October 9, 2017, the Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility. On November 8, 2017, the Partnership acquired mineral and royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price of approximately $7.3 million in various counties in Arkansas. The Partnership funded this acquisition with borrowings under its secured revolving credit facility. On December 13, 2017, the Partnership acquired a diverse package of mineral and overriding royalty interests for an aggregate purchase price of approximately $1.3 million. The core positions are located in California and Wyoming and the package also includes small interests located in Kansas, Arkansas, Texas and Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2019
DERIVATIVES
DERIVATIVES	NOTE 4—DERIVATIVES The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. At December 31, 2019 , the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The Partnership hedges its daily production based on the amount of debt and/or preferred equity as a percent of its enterprise value. This amount constitutes approximately 18% of daily oil and natural gas production. The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. The Partnership records all derivative contracts at fair value. Changes in the fair values of the Partnership’s derivative instruments are presented on a net basis in the accompanying consolidated statements of operations and consisted of the following: Year Ended December 31, Period from 2019 2018 2017 Beginning fair value of commodity derivative instruments $ 4,227,946 $ (318,829) $ — (Loss) gain on commodity derivative instruments (1,732,321) 3,331,548 (318,829) Net cash (received) paid on settlements of derivative instruments (1,691,124) 1,215,227 — Ending fair value of commodity derivative instruments $ 804,501 $ 4,227,946 $ (318,829) The following table presents the fair value of the Partnership’s derivative contracts as of December 31, 2019 and 2018: December 31, December 31, Classification Balance Sheet Location 2019 2018 Assets: Current asset Commodity derivative assets $ 687,933 $ 2,981,117 Long-term asset Commodity derivative assets 116,568 1,246,829 Liabilities: Current liability Commodity derivative liabilities — — Long-term liability Commodity derivative liabilities — — $ 804,501 $ 4,227,946 At December 31, 2019, the Partnership’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional Weighted Average Range (per Bbl) Volumes (Bbl) Fixed Price (per Bbl) Low High December 2019 19,034 $ 61.47 $ 53.07 $ 63.47 January 2020 - December 2020 224,356 $ 55.48 $ 50.45 $ 61.43 January 2021 - December 2021 238,307 $ 53.49 $ 50.79 $ 56.10 Natural Gas Price Swaps Notional Weighted Average Range (per MMBtu) Volumes (MMBtu) Fixed Price (per MMBtu) Low High January 2020 - December 2020 3,582,862 $ 2.64 $ 2.51 $ 2.94 January 2021 - December 2021 3,503,617 $ 2.49 $ 2.33 $ 2.85

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2019
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	NOTE 5—FAIR VALUE MEASUREMENTS The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the consolidated balance sheets approximated fair value at December 31, 2019 and 2018 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below. · Level 1—Unadjusted quoted market 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 years ended December 31, 2019 and 2018. 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. The following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy: Fair Value Measurements Using Level 1 Level 2 Level 3 Effect of Counterparty Netting Total December 31, 2019 Assets Commodity derivative contracts $ — $ 804,501 $ — $ — $ 804,501 December 31, 2018 Assets Commodity derivative contracts $ — $ 4,227,946 $ — $ — $ 4,227,946

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	12 Months Ended
	Dec. 31, 2019
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES	NOTE 6—OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties consist of the following: December 31, December 31, 2019 2018 Oil and natural gas properties Proved properties $ 758,313,233 $ 538,290,590 Unevaluated properties 275,041,784 280,304,353 Less: accumulated depreciation, depletion and impairment (328,913,425) (107,779,453) Total oil and natural gas properties $ 704,441,592 $ 710,815,490 Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within five years of the date of the acquisition of the unevaluated properties. The Partnership assesses all items classified as unevaluated property on an annual basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The Partnership recorded an impairment on its oil and natural gas properties of $169.2 million during the year ended December 31, 2019 as a result of its quarterly full cost ceiling analysis and a decline in the 12-month average price of oil and natural gas. The Partnership recorded an impairment expense on its oil and natural gas properties of $67.3 million during the year ended December 31, 2018, as a result of its quarterly full cost ceiling analysis during the three months ended March 31, 2018 and December 31, 2018. As of December 31, 2019, the 12-month average prices of oil and natural gas were $55.69 per Bbl of oil and $2.58 per Mcf of natural gas. These prices represent a 15.1% and 16.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2018, which were $65.56 per Bbl of oil and $3.10 per Mcf of natural gas. No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017 or for the Predecessor 2017 Period.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2019
LONG-TERM DEBT.
LONG-TERM DEBT	NOTE 7—LONG-TERM DEBT In connection with its IPO, on January 11, 2017, the Partnership entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto. On July 12, 2018, in connection with the Haymaker Acquisition, the Partnership entered into an amendment (the “Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement ( the 2017 Credit Agreement as amended by the Credit Agreement Amendment, the “Amended Credit Agreement”), by and among the Partnership, certain subsidiaries of the Partnership, as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto. The Credit Agreement Amendment amends the 2017 Credit Agreement to provide for, among other things, (i) the addition of the subsidiaries the Partnership acquired in the Haymaker Acquisition, as well as the Operating Company, as guarantors under the Amended Credit Agreement, (ii) limitations on the Partnership’s ability to incur certain debt or issue preferred equity, (iii) limitations on redemptions of the Series A preferred units and the ability of the Partnership and the restricted subsidiaries of the Partnership to make distributions and other restricted payments, in each case, unless certain conditions are satisfied, (iv) increased limitations on the Partnership’s ability to dispose of certain assets or encumber certain assets, (v) a decrease in the applicable margin under the 2017 Credit Agreement, which varies based upon the level of borrowing base usage, by 0.25% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 2.00% to 3.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement) and (vi) the addition of certain restrictions on the Partnership’s and the Operating Company’s ability to take certain actions or amend their organizational documents. The Amended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The Amended Credit Agreement also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The Amended Credit Agreement also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control. The Credit Agreement Amendment increased commitments under the Amended Credit Agreement from $50.0 million to $200.0 million. Under the Amended Credit Agreement, availability under the secured revolving credit facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base under the Amended Credit Agreement was set at $200.0 million. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased to $500.0 million, subject to the limitations of our borrowing base and the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The borrowing base will be redetermined semiannually on May 1 and November 1 of each year based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of the Partnership’s wholly owned subsidiaries. In connection with the May redetermination, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million and the borrowing base was increased from $200.0 million to $300.0 million. In connection with the November 1, 2019 redetermination under the Amended Credit Agreement, the borrowing base was reaffirmed at $300.0 million and total commitments will remain at $225.0 million. The secured revolving credit facility matures on February 8, 2022. During the year ended December 31, 2019, the Partnership borrowed an additional $12.8 million under the secured revolving credit facility. As of December 31, 2019, the Partnership’s outstanding balance was $100.1 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2019. As of December 31, 2019, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% or Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the year ended December 31, 2019, the weighted average interest rate on the Partnership’s outstanding borrowings was 4.58%.

PREFERRED UNITS

PREFERRED UNITS	12 Months Ended
	Dec. 31, 2019
PREFERRED UNITS
PREFERRED UNITS	NOTE 8—PREFERRED UNITS Preferred Purchase Agreement In July 2018, in connection with the closing of the Haymaker Acquisition, the Partnership completed the private placement of 110,000 Series A preferred units to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $110.0 million (the “Preferred Unit Transaction”). Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the third anniversary of the original issuance date, and board appointment rights beginning the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units. The Series A preferred units are convertible by the Series A Purchasers after two years at a 30% discount to the issue price, subject to certain conditions. The Partnership may redeem the Series A preferred units at any time. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions. For purposes of the Series A preferred units , “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the July 12, 2018 (the “Series A Issuance Date”), a 13.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary of the Series A Issuance Date, a 14.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the Series A Issuance Date, a 15.0% internal rate of return with respect to the Series A preferred units. The following table summarizes the changes in the number of the Series A preferred units: Series A Preferred Units Balance at December 31, 2018 110,000 Balance at December 31, 2019 110,000

UNITHOLDERS' EQUITY AND PARTNER

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS	12 Months Ended
	Dec. 31, 2019
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS	NOTE 9—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS The Partnership has limited partner units. At December 31, 2019, the Partnership had a total of 23,518,652 common units issued and outstanding and 25,557,606 Class B units outstanding. The following table summarizes the changes in the number of the Partnership’s common units: Common Units Balance at December 31, 2018 18,056,487 Conversion of Class B units 5,465,000 Restricted units used for tax withholding (2,835) Balance at December 31, 2019 23,518,652 The following table presents information regarding the common unit cash distributions approved by the Board of Directors for the periods presented: Amount per Date Unitholder Payment Common Unit Declared Record Date Date Q1 2019 $ 0.37 April 26, 2019 May 6, 2019 May 13, 2019 Q2 2019 $ 0.39 July 26, 2019 August 5, 2019 August 12, 2019 Q3 2019 $ 0.42 October 25, 2019 November 4, 2019 November 11, 2019 Q4 2019 $ 0.38 January 24, 2020 February 3, 2020 February 10, 2020 Q1 2018 $ 0.42 April 27, 2018 May 7, 2018 May 14, 2018 Q2 2018 $ 0.43 July 27, 2018 August 6, 2018 August 13, 2018 Q3 2018 $ 0.45 October 26, 2018 November 5, 2018 November 12, 2018 Q4 2018 $ 0.40 January 25, 2019 February 4, 2019 February 11, 2019 Q1 2017 (1) $ 0.23 May 2, 2017 May 8, 2017 May 15, 2017 Q2 2017 $ 0.30 July 28, 2017 August 7, 2017 August 14, 2017 Q3 2017 $ 0.31 October 27, 2017 November 6, 2017 November 13, 2017 Q4 2017 $ 0.36 January 26, 2018 February 7, 2018 February 14, 2018 (1) The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017. The following table summarizes the changes in the number of the Partnership’s Class B units: Class B Units Balance at December 31, 2018 19,453,258 Class B units issued for acquisitions 11,569,348 Conversion of Class B units (5,465,000) Balance at December 31, 2019 25,557,606 Holders of the Class B units, are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units but prior to distributions on the common units and OpCo common units. The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

EARNINGS (LOSS) PER UNIT

EARNINGS (LOSS) PER UNIT	12 Months Ended
	Dec. 31, 2019
EARNINGS (LOSS) PER UNIT
EARNINGS (LOSS) PER UNIT	NOTE 10—EARNINGS (LOSS) PER UNIT Basic earnings (loss) per unit (“EPU”) is calculated by dividing net income (loss) attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested restricted units granted under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) for its employees, directors and consultants, potential conversion of Class B units and unvested options granted under the Predecessor’s long-term incentive plan as described in Note 11—Unit-Based Compensation. The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted earnings (loss) per unit: Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Net (loss) income attributable to common units $ (83,032,282) $ (56,767,549) $ 1,715,740 $ (496,856) Weighted average number of common units outstanding: Basic 21,192,714 18,442,234 16,336,871 604,137 Effect of dilutive securities: Series A preferred units — — — — Class B units — — — — Restricted units — — 118,731 — Diluted 21,192,714 18,442,234 16,455,602 604,137 Net (loss) income attributable to common units Basic $ (3.92) $ (3.08) $ 0.11 $ (0.82) Diluted $ (3.92) $ (3.08) $ 0.10 $ (0.82) The calculation of diluted net loss per share for the years ended December 31, 2019 and 2018 excludes the assumed conversion of Series A preferred units to common units, the assumed conversion of Class B units to common units and 739,479 and 1,157,924 shares of unvested restricted units, respectively, 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 consolidated statements of operations for this period.

UNIT-BASED COMPENSATION

UNIT-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2019
UNIT-BASED COMPENSATION
UNIT-BASED COMPENSATION	NOTE 11—UNIT-BASED COMPENSATION On September 23, 2018, the General Partner entered into the First Amendment to the LTIP, which increased the number of common units eligible for issuance under the LTIP by 2,500,000 common units for a total of 4,541,600 common units. The Partnership’s LTIP authorizes grants to its employees, directors and consultants. The restricted units issued under the Partnership’s LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants is treated in the same manner as that of the employees and directors. Distributions related to the restricted units are paid concurrently with the Partnership’s distributions for common units. The fair value of the Partnership’s restricted units issued under the LTIP to the Partnership’s employees, directors and consultants is determined by utilizing the market value of the Partnership’s common units on the respective grant date. The following table presents a summary of the Partnership’s unvested restricted units. Weighted Weighted Average Average Grant-Date Remaining Fair Value Contractual Units per Unit Term Unvested at December 31, 2018 1,157,924 $ 18.054 2.696 years Vesting (418,445) 18.045 — Unvested at December 31, 2019 739,479 $ 18.059 1.335 years Prior to the IPO, the Predecessor had a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options as compensation for services performed for the Predecessor. For the Predecessor 2017 Period, total compensation expense for awards under the long-term incentive plan was $0.05 million and is included general and administrative expenses in the 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.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
INCOME TAXES
INCOME TAXES	NOTE 12—INCOME TAXES As discussed further in Note 1, on May 28, 2018, the Board of Directors unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. The Partnership’s effective income tax rate was (0.6)% for the year ended December 31, 2019. The Partnership incurred a book loss for the current year, however, has a current income tax expense of $0.9 million due to special allocations from the Operating Company. Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Current Federal $ 812,913 $ — $ — $ — State 86,512 24,681 — — Total Current 899,425 24,681 — — Deferred Federal — — — — State — — — — Total Deferred — — — — Provision for income taxes $ 899,425 $ 24,681 $ — $ — The Partnership’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items: Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Net (loss) income before taxes $ (157,308,520) $ (52,257,542) $ 1,715,740 $ (496,856) Statutory rate 21 % 21 % 35 % 35 % Income tax expense computed at statutory rate (33,034,789) (10,974,084) 600,509 (173,900) Reconciling items: State income taxes 72,280 (70,441) — — Texas margins tax — 24,681 — — Change in tax status — (20,038,820) — — Non-controlling interest 18,721,170 (360,082) — — Income (loss) at OpCo 15,130,685 10,598,375 (600,509) 173,900 Change in valuation allowance - federal 80,520 20,771,214 — — Change in valuation allowance - state (70,441) 70,441 — — Other, net — 3,397 — — Provision for income taxes $ 899,425 $ 24,681 $ — $ — Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Partnership’s deferred taxes are detailed in the table below. Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Deferred tax asset Outside basis in OpCo $ 20,050,732 $ 21,036,307 $ — $ — Federal tax loss carryforwards — 622,775 — — State tax loss carryforwards — 70,441 — — Deferred tax asset 20,050,732 21,729,523 — — Valuation allowance (20,050,732) (20,841,655) — — Net deferred tax asset $ — $ 887,868 $ — $ — Deferred tax liability Derivative instruments and other — 887,868 — — Net deferred tax liability $ — $ 887,868 $ — $ — Reflected in the accompanying balance sheets as: Net deferred tax asset $ — $ — $ — $ — Net deferred tax liability $ — $ — $ — $ — The tax years ended December 31, 2016 through 2019 remain open to examination under the applicable statute of limitations in the United States and other jurisdictions in which the Partnership and its subsidiaries file income tax returns. In some instances, state statutes of limitations are longer than those under United States federal tax law . The Partnership believes that it is more likely than not that the benefit from the outside basis differences in the Partnership’s investment in the Operating Company will not be realized. In recognition of this risk, the Partnership has provided a valuation allowance of $20.1 million on the deferred tax assets relating to the outside basis differences in the Partnership’s investment in the Operating Company. As of December 31, 2019, the Partnership has not recorded a reserve for any uncertain tax positions.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2019
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	NOTE 13—RELATED PARTY TRANSACTIONS In connection with the IPO, the Partnership entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), Steward Royalties, LLC (“Steward Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”) pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders. During the year ended December 31, 2019, no monthly services fee was paid to BJF Royalties or Steward Royalties. During the year ended December 31, 2019, the Partnership made payments to Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $526,855, $120,000, $327,671 and $498,306, respectively. Certain consultants who provide services under the management services agreements are also granted restricted units under the Partnership’s LTIP. As of December 31, 2018, the Partnership had an outstanding receivable from Rivercrest Capital Management and certain employees of $7,773, which is included in accounts receivable and other current assets in the accompanying audited consolidated balance sheet. During the Predecessor 2017 Period, the Predecessor had certain related party receivables and payables; however, such amounts are de minimis.

ADMINISTRATIVE SERVICES

ADMINISTRATIVE SERVICES	12 Months Ended
	Dec. 31, 2019
ADMINISTRATIVE SERVICES
ADMINISTRATIVE SERVICES	NOTE 14—ADMINISTRATIVE SERVICES Management Services Agreement The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business efforts. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the Board of Directors and their affiliated entities. See Note 13―Related Party Transactions. Transition Services Agreement On March 25, 2019, in connection with the Phillips Acquisition, the Partnership entered into a Transition Services Agreement (the “Transition Services Agreement”) with Fortis Administrative Services, LLC (“Fortis”). Pursuant to the Transition Services Agreement, Fortis provided certain administrative services and accounting assistance on a transitional basis for total compensation of $300,000 from April 1, 2019 through June 1, 2019, at which point, the Transition Services Agreement was terminated.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2019
COMMITMENTS AND CONTINGENCIES.
COMMITMENTS AND CONTINGENCIES	NOTE 15—COMMITMENTS AND CONTINGENCIES Leases The Partnership leases certain office space under non-cancelable operating leases that end at various dates through 2028. The Partnership recognizes operating lease expense on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2019. The total operating lease expense recorded for the year ended December 31, 2019 was approximately $0.3 million. The total operating lease expense recorded for both the year ended December 31, 2018 and for and the period from February 8, 2017 to December 31, 2017 was approximately $0.1 million. Operating lease expense was de minimis for the Predecessor 2017 Period. Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2019: Years Ending December 31, 2020 $ 474,334 2021 478,428 2022 478,837 2023 480,579 2024 486,323 Thereafter 2,223,948 Total $ 4,622,449 Litigation Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2019
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 16—SUBSEQUENT EVENTS The Partnership has evaluated events that occurred subsequent to December 31, 2019 in the preparation of its financial statements. In January 2020, in connection with the Joint Venture, the Partnership paid capital contributions of $0.8 million. Springbok Acquisition On January 9, 2020, the Partnership agreed to acquire all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”) from the owners of such entities (collectively, the “Springbok Sellers”). The proposed aggregate consideration for the Springbok Acquisition consists of (i) $95.0 million in cash, (ii) the issuance of 2,224,358 common units and (iii) the issuance of 2,497,133 OpCo common units and an equal number of Class B units. In connection with the execution of the purchase agreement, the Partnership paid a deposit of approximately $9.5 million on the cash portion of the purchase price, which was funded by borrowings under its senior secured credit facility. At the time of the filing of this Annual Report, the Springbok Acquisition has not closed and is expected to close in April 2020. The closing of the Springbok Acquisition remains subject to the satisfaction of certain closing conditions, and there can be no assurance that it will be completed as planned or at all . 2020 Equity Offering In January 2020, the Partnership completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $74.0 million (the “2020 Equity Offering”). The Partnership used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under the Partnership’s Amended Credit Agreement. In connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units pursuant to the exercise of the underwriters’ option to purchase additional common units. The Partnership did not receive any proceeds from the sale of the common units by the selling unitholders. 2020 Partial Redemption of Preferred Units On February 12, 2020, the Partnership completed the redemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million. Transactions in Common Units On January 27, 2020, EIGF Aggregator III LLC exchanged 702,071 OpCo common units and Class B units, together, for an equal number of common units of the Partnership. Also, on January 27, 2020, TE Drilling Aggregator LLC exchanged 47,929 OpCo common units and Class B units, together, for an equal number of common units of the Partnership. On January 28, 2020, EIGF Aggregator III LLC exchanged 3,897,483 OpCo common units and Class B units, together, for an equal number of common units of the Partnership. Also, on January 28, 2020, TE Drilling Aggregator LLC exchanged 266,076 OpCo common units and Class B units, together, for an equal number of common units of the Partnership. Distributions On February 5, 2020, the Partnership paid a quarterly cash distribution on the Series A preferred units of $1.9 million for the quarter ended December 31, 2019. On February 6, 2020, the Operating Company paid a quarterly cash distribution of $0.387662 to holders of OpCo common units. As to the Partnership, $0.007662 of the distribution corresponds to a tax payment made by the Partnership from cash reserves in the fourth quarter of 2019. The fourth quarter 2019 tax payment made by the Partnership was generated by a gross income allocation related to the Series A preferred units, which were issued in connection with the Haymaker Acquisition. Under the limited liability company agreement of the Operating Company, the Partnership is not reimbursed by the Operating Company for federal income taxes paid by the Partnership. On February 6, 2020 , the Partnership paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of approximately $24,808 for the quarter ended December 31, 2019. On January 24, 2020, the Board of Directors declared a quarterly cash distribution of $0.38 per common unit for the quarter ended December 31, 2019. The distribution was paid on February 10, 2020 to common unitholders of record as of the close of business on February 3, 2020.

SUPPLEMENTAL OIL AND GAS RESERV

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2019
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)	NOTE 17—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) The Partnership has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Partnership’s accompanying consolidated statements of operations for information about results of 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, December 31, 2019 2018 Oil, natural gas and NGL interests Proved properties $ 758,313,233 $ 538,290,590 Unevaluated properties 275,041,784 280,304,353 Total oil, natural gas and NGL interests 1,033,355,017 818,594,943 Accumulated depreciation, depletion, accretion and impairment (328,913,425) (107,779,453) Net oil, natural gas and NGL interests capitalized $ 704,441,592 $ 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: Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Acquisition costs Proved properties $ 104,199,579 $ 243,227,632 $ 297,609,797 $ — Unevaluated properties 110,050,000 288,334,110 — — Total 214,249,579 531,561,742 297,609,797 — Development costs Proved properties — — — — Total — — — — Total costs incurred on oil, natural gas and NGL activities $ 214,249,579 $ 531,561,742 $ 297,609,797 $ — Results of Operations from Oil, Natural Gas and NGL 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 or Predecessor’s oil, natural gas and NGL operations. Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Oil, natural gas and NGL revenues $ 107,480,446 $ 65,713,112 $ 29,943,920 $ 318,310 Lease bonus and other income 2,477,145 1,213,550 721,172 — Production and ad valorem taxes (7,719,949) (4,399,667) (2,452,058) (19,651) Depreciation and depletion expense (52,118,367) (25,213,043) (15,394,238) (113,639) Impairment of oil and natural gas properties (169,150,255) (67,311,501) — — Marketing and other deductions (8,145,397) (4,652,313) (1,648,895) (110,534) Results of operations from oil, natural gas and NGLs $ (127,176,377) $ (34,649,862) $ 11,169,901 $ 74,486 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, 2019, 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 NGL 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. PUD 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 January 1, 2017 7,210 50,390 1,982 17,590 Revisions of previous estimates (1) (193) (1,535) 666 217 Purchase of minerals in place (2) 362 16,312 274 3,355 Extensions, discoveries and other additions (3) 505 2,261 91 973 Production (421) (3,512) (175) (1,181) 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 (4) 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 Revisions of previous estimates (1) 849 25,398 684 5,766 Purchase of minerals in place (5) 1,787 13,129 686 4,661 Production (1,113) (17,046) (561) (4,515) Net proved reserves at December 31, 2019 12,318 148,742 6,455 43,563 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 December 31, 2019 11,303 141,181 6,079 40,912 Net proved undeveloped reserves December 31, 2017 2,179 16,415 636 5,551 December 31, 2018 1,612 10,940 583 4,018 December 31, 2019 1,015 7,561 376 2,651 (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 $29.3 million of mineral and royalty interests, the largest of which being a package in the Anadarko Basin, and also includes additional mineral and royalty interests in Texas, Louisiana, Wyoming, California, North Dakota, Utah, New Mexico, Arkansas, and Kansas. (3) Includes discoveries and additions primarily related to active drilling on the Partnership’s acreage primarily in the Permian Basin, Eagle Ford Shale. (4) 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. (5) Includes the acquisition of three packages of mineral and royalty interests for a total of $103.8 million. The first acquisition totaling $58.4 million consists of mineral and royalty interests primarily in the Eagle Ford Shale, Permian Basin, East Texas Region and Appalachia Region. The second acquisition totaling $9.4 million consists of mineral and royalty interests in the Mid-Continent Region. The third acquisition totaling $36.0 million consists of mineral and royalty interests in the Eagle Ford Shale. 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 NGL reserves of the properties is as follows (in thousands): Year Ended December 31, 2019 2018 2017 Future cash inflows $ 1,025,430 $ 1,056,464 $ 562,967 Future production costs (78,061) (79,724) (45,652) Future state margin taxes (32,377) (32,885) (2,790) Future income tax expense (33,235) (41,241) — Future net cash flows 881,757 902,614 514,525 Less 10% annual discount to reflect timing of cash flows (481,786) (504,247) (298,973) Standard measure of discounted future net cash flows $ 399,971 $ 398,367 $ 215,552 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 2019, 2018 and 2017 were $55.69, $65.56 and $51.34 per barrel for crude oil and $2.58, $3.10 and $2.98 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, 2019 2018 2017 Standardized measure - beginning of year $ 398,367 $ 215,552 $ 159,275 Sales, net of production costs (93,942) (56,661) (29,288) Net changes of prices and production costs related to future production (72,875) 11,355 21,946 Extensions, discoveries and improved recovery, net of future production costs — — 10,064 Revisions of previous quantity estimates, net of related costs 56,666 16,385 2,248 Net changes in state margin taxes 191 (13,271) 301 Net changes in income taxes 3,752 (17,232) — Accretion of discount 42,808 21,555 15,928 Purchases of reserves in place 59,953 175,885 23,309 Timing differences and other 5,051 44,799 11,769 Standardized measure - end of year $ 399,971 $ 398,367 $ 215,552

SELECTED QUARTERLY FINANCIAL DA

SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED	12 Months Ended
	Dec. 31, 2019
SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED
SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED	KIMBELL ROYALTY PARTNERS, LP SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED Selected Quarterly Financial Information—Unaudited Quarterly financial data was as follows for the periods indicated. First Quarter Second Quarter Third Quarter Fourth Quarter 2019 Total revenue $ 17,947,209 $ 31,936,601 $ 32,978,851 $ 25,362,609 Net loss attributable to common units $ (3,687,252) $ (11,758,374) $ (16,261,051) $ (51,325,605) Net loss attributable to common units Basic $ (0.21) $ (0.54) $ (0.73) $ (2.27) Diluted $ (0.21) $ (0.54) $ (0.73) $ (2.27) Cash distributions declared and paid $ 0.37 $ 0.39 $ 0.42 $ 0.38 Total assets $ 906,158,146 $ 868,725,908 $ 828,745,127 $ 748,594,054 Long-term debt $ 87,309,544 $ 87,309,544 $ 91,261,477 $ 100,135,477 Mezzanine equity $ 70,275,978 $ 71,820,563 $ 73,365,147 $ 74,909,732 Unitholders' equity $ 314,985,017 $ 360,133,072 $ 343,138,843 $ 283,827,721 Noncontrolling interest $ 427,617,585 $ 343,165,767 $ 310,744,268 $ 281,157,393 First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Total revenue $ 10,891,338 $ 10,707,898 $ 18,407,956 $ 30,251,018 Net (loss) income attributable to common units $ (52,824,471) $ 1,378,295 $ (3,711,798) $ (1,609,575) Net (loss) income attributable to common units Basic $ (3.23) $ 0.08 $ (0.15) $ (0.10) Diluted $ (3.23) $ 0.08 $ (0.15) $ (0.10) Cash distributions declared and paid $ 0.42 $ 0.43 $ 0.45 $ 0.40 Total assets $ 237,201,565 $ 249,318,570 $ 683,893,161 $ 753,285,373 Long-term debt $ 30,843,593 $ 42,972,997 $ 148,309,544 $ 87,309,544 Mezzanine equity $ — $ — $ 67,904,422 $ 69,449,006 Partners' capital / unitholders' equity $ 203,848,774 $ 198,879,415 $ 247,441,471 $ 300,794,564 Noncontrolling interest $ — $ — $ 209,450,877 $ 291,932,233

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2019
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation	Basis of Presentation The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (‘‘GAAP’’). A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.
Segment Reporting	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.
Management Estimates	Management Estimates The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, valuation of commodity derivative financial instruments and equity‑based compensation. The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.
Reclassification of Prior Period Presentation	Reclassification of Prior Period Presentation Certain prior period amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on previously reported net income (loss), total cash flows from operations or working capital.
Cash and Cash Equivalents	Cash and Cash Equivalents The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.
Accounts Receivable	Accounts Receivable Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. The Partnership estimates and records an allowance for doubtful accounts when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2019, and 2018, no allowance for doubtful accounts is deemed necessary based upon a review of current receivables and the lack of historical write offs.
Derivative Financial Instruments	Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statement of operations within loss on commodity derivative instruments.
Property and Equipment	Property and Equipment Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within five years. While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12‑month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO and were excluded from the from the ceiling test calculation pursuant to an exemption from the United States Securities and Exchange Commission (“SEC”), which remained effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that the Partnership was 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. No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). The Partnership recorded an impairment on its oil and natural gas properties of $169.2 million during the year ended December 31, 2019, as a result of its quarterly full cost ceiling analysis and a decline in the 12-month average price of oil and natural gas. The Partnership recorded an impairment expense on its oil and natural gas properties of $67.3 million during the year ended December 31, 2018. Of this amount, an impairment expense of $54.8 million was recorded as a result of the Partnership’s quarterly full-cost ceiling analysis for the three months ended March 31, 2018 following the expiration of the aforementioned exemption and an impairment expense of $12.6 million was recorded for the three months ended December 31, 2018 as a result of the Dropdown (as defined in Note 3—Acquisitions and Divestitures) purchase price exceeding the value of the proved developed reserves added to the full-cost ceiling. As the Partnership does not have the history with its more recent acquisitions made since the IPO and given the non-operating nature of our interests, it can no longer accurately predict the timing of additional drilling. Thus, the Partnership does not intend to book proved undeveloped (“PUD”) reserves going forward. Accordingly, additional impairment charges could be recorded in connection with future acquisitions. While drilling continues to occur on the Partnership’s properties, without the recognition of PUD reserves since the IPO, additional impairments may be required particularly when oil, natural gas, and NGL prices decline. The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2019 or December 31, 2018, the period from February 8, 2017 to December 31, 2017 or the Predecessor 2017 Period. Due to the nature of the Partnership’s and the Predecessor’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2019 or December 31, 2018, the period from February 8, 2017 to December 31, 2017 or the Predecessor 2017 Period.
Other Current Liabilities	Other Current Liabilities Other current liabilities consist primarily of Series A preferred unit and Class B unit distributions, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short term operating lease liabilities.
Income Taxes	Income Taxes As discussed further in Note 1—Organization and Basis of Presentation, on May 28, 2018, the Partnership announced that the Board of Directors had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership incurred de minimis amounts of income taxes during the years ended December 31, 2019 and 2018. Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership had no uncertain tax positions at December 31, 2019 and 2018. The Partnership and Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2019 and December 31, 2018, the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions. The Partnership has filed all tax returns to date that are currently due. For the Predecessor, tax years after December 31, 2014 remain subject to possible examination by taxing authorities although no such examination has been requested.
Concentration of Credit Risk	Concentration of Credit Risk The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations. At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits. During the year ended December 31, 2019, the Partnership’s top purchaser accounted for approximately 6.0% of oil, natural gas and NGL sales revenue. During the year ended December 31, 2018, the Partnership’s top purchaser accounted for approximately 10% of oil, natural gas and NGL sales revenue. During the period from February 8, 2017 to December 31, 2017, one purchaser accounted for approximately 14% of oil, natural gas and NGL sales revenue.
Revenue from Contracts with Customers	Revenue from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index. Royalty income from oil, natural gas and NGL sales The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and NGLs. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s royalty income contracts. Contract balances Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606 . Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for one to four months after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and NGL contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.
Fair Value Measurements	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. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements.
New Accounting Pronouncements	New Accounting Pronouncements Recently Adopted Pronouncements In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016‑02, “Leases.” ASU 2016‑02 requires the recognition of right-of-use (“ROU”) assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year, with early adoption permitted. The Partnership adopted this update using the modified retrospective approach, effective January 1, 2019. The adoption of this update did not have a material impact on the Partnership’s results of operations for the year ended December 31, 2019. The Partnership evaluated whether its contractual arrangements contain leases at the inception of such arrangements. Specifically, the Partnership considered whether it can control the underlying asset and have the right to obtain substantially all of the economic benefits or outputs from the asset. Substantially all of the Partnerships leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s ROU operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying consolidated balance sheet as of December 31, 2019. Current operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of December 31, 2019 was 9.34 years. Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the Amended Credit Agreement, as defined in Note 7—Long-Term Debt, as of January 1, 2019. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the year ended December 31, 2019. Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2019. The total operating lease expense recorded for the year ended December 31, 2019 was approximately $0.3 million. Currently, the most substantial contractual arrangement that the Partnership has classified as an operating lease is the main office space used for operations. In July 2019, the Partnership became the lessee in several other related lease agreements for additional office space. In addition, the Partnership was involved in the construction and design of the underlying assets. The underlying assets were capitalized in July 2019 upon commencement of the lease. Future minimum lease commitments as of December 31, 2019 were as follows: Total 2020 2021 2022 2023 2024 Thereafter Operating leases $ 4,622,449 $ 474,334 $ 478,428 $ 478,837 $ 480,579 $ 486,323 $ 2,223,948 Less: Imputed Interest (1,243,903) Total $ 3,378,546 In July 2018, the FASB issued ASU 2018-09, “Codification Improvements.” This update provides clarification and corrects unintended application of the guidance in various sections. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations for the year ended December 31, 2019. In July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842, Leases.” This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations for the year ended December 31, 2019. Accounting Pronouncements Not Yet Adopted In August 2018, the FASB issued ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement.” This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. The FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments,” which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for the interim and annual periods beginning after December 31, 2018, and will be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Partnership does not plan to early adopt and is currently evaluating the effect the guidance will have on its consolidated financial statements; however, the impact is not expected to be material. In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740) Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2019
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Schedule of future minimum lease commitments	Future minimum lease commitments as of December 31, 2019 were as follows: Total 2020 2021 2022 2023 2024 Thereafter Operating leases $ 4,622,449 $ 474,334 $ 478,428 $ 478,837 $ 480,579 $ 486,323 $ 2,223,948 Less: Imputed Interest (1,243,903) Total $ 3,378,546

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2019
DERIVATIVES
Schedule of changes in fair value of derivative instruments	Year Ended December 31, Period from 2019 2018 2017 Beginning fair value of commodity derivative instruments $ 4,227,946 $ (318,829) $ — (Loss) gain on commodity derivative instruments (1,732,321) 3,331,548 (318,829) Net cash (received) paid on settlements of derivative instruments (1,691,124) 1,215,227 — Ending fair value of commodity derivative instruments $ 804,501 $ 4,227,946 $ (318,829)
Schedule of derivative contracts	December 31, December 31, Classification Balance Sheet Location 2019 2018 Assets: Current asset Commodity derivative assets $ 687,933 $ 2,981,117 Long-term asset Commodity derivative assets 116,568 1,246,829 Liabilities: Current liability Commodity derivative liabilities — — Long-term liability Commodity derivative liabilities — — $ 804,501 $ 4,227,946
Schedule of commodity derivative contracts	December 31, December 31, Classification Balance Sheet Location 2019 2018 Assets: Current asset Commodity derivative assets $ 687,933 $ 2,981,117 Long-term asset Commodity derivative assets 116,568 1,246,829 Liabilities: Current liability Commodity derivative liabilities — — Long-term liability Commodity derivative liabilities — — $ 804,501 $ 4,227,946 At December 31, 2019, the Partnership’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional Weighted Average Range (per Bbl) Volumes (Bbl) Fixed Price (per Bbl) Low High December 2019 19,034 $ 61.47 $ 53.07 $ 63.47 January 2020 - December 2020 224,356 $ 55.48 $ 50.45 $ 61.43 January 2021 - December 2021 238,307 $ 53.49 $ 50.79 $ 56.10 Natural Gas Price Swaps Notional Weighted Average Range (per MMBtu) Volumes (MMBtu) Fixed Price (per MMBtu) Low High January 2020 - December 2020 3,582,862 $ 2.64 $ 2.51 $ 2.94 January 2021 - December 2021 3,503,617 $ 2.49 $ 2.33 $ 2.85

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
FAIR VALUE MEASUREMENTS
Schedule of assets and liabilities measured at fair value on a recurring basis	The following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy: Fair Value Measurements Using Level 1 Level 2 Level 3 Effect of Counterparty Netting Total December 31, 2019 Assets Commodity derivative contracts $ — $ 804,501 $ — $ — $ 804,501 December 31, 2018 Assets Commodity derivative contracts $ — $ 4,227,946 $ — $ — $ 4,227,946

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2019
OIL AND NATURAL GAS PROPERTIES
Schedule of oil and natural gas properties	December 31, December 31, 2019 2018 Oil and natural gas properties Proved properties $ 758,313,233 $ 538,290,590 Unevaluated properties 275,041,784 280,304,353 Less: accumulated depreciation, depletion and impairment (328,913,425) (107,779,453) Total oil and natural gas properties $ 704,441,592 $ 710,815,490

PREFERRED UNITS (Tables)

PREFERRED UNITS (Tables)	12 Months Ended
	Dec. 31, 2019
Series A Preferred Units
Preferred units
Summary of the changes in the number of the Series A Preferred Units	Series A Preferred Units Balance at December 31, 2018 110,000 Balance at December 31, 2019 110,000

UNITHOLDERS' EQUITY AND PARTN_2

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Tables)	12 Months Ended
	Dec. 31, 2019
Common units
Schedule of distributions approved by the Board of Directors	Amount per Date Unitholder Payment Common Unit Declared Record Date Date Q1 2019 $ 0.37 April 26, 2019 May 6, 2019 May 13, 2019 Q2 2019 $ 0.39 July 26, 2019 August 5, 2019 August 12, 2019 Q3 2019 $ 0.42 October 25, 2019 November 4, 2019 November 11, 2019 Q4 2019 $ 0.38 January 24, 2020 February 3, 2020 February 10, 2020 Q1 2018 $ 0.42 April 27, 2018 May 7, 2018 May 14, 2018 Q2 2018 $ 0.43 July 27, 2018 August 6, 2018 August 13, 2018 Q3 2018 $ 0.45 October 26, 2018 November 5, 2018 November 12, 2018 Q4 2018 $ 0.40 January 25, 2019 February 4, 2019 February 11, 2019 Q1 2017 (1) $ 0.23 May 2, 2017 May 8, 2017 May 15, 2017 Q2 2017 $ 0.30 July 28, 2017 August 7, 2017 August 14, 2017 Q3 2017 $ 0.31 October 27, 2017 November 6, 2017 November 13, 2017 Q4 2017 $ 0.36 January 26, 2018 February 7, 2018 February 14, 2018 (1) The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.
Common Units
Common units
Schedule of changes in Partnership's units	Common Units Balance at December 31, 2018 18,056,487 Conversion of Class B units 5,465,000 Restricted units used for tax withholding (2,835) Balance at December 31, 2019 23,518,652
Class B
Common units
Schedule of changes in Partnership's units	Class B Units Balance at December 31, 2018 19,453,258 Class B units issued for acquisitions 11,569,348 Conversion of Class B units (5,465,000) Balance at December 31, 2019 25,557,606

EARNINGS (LOSS) PER UNIT (Table

EARNINGS (LOSS) PER UNIT (Tables)	12 Months Ended
	Dec. 31, 2019
EARNINGS (LOSS) PER UNIT
Schedule of earnings (loss) per unit	Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Net (loss) income attributable to common units $ (83,032,282) $ (56,767,549) $ 1,715,740 $ (496,856) Weighted average number of common units outstanding: Basic 21,192,714 18,442,234 16,336,871 604,137 Effect of dilutive securities: Series A preferred units — — — — Class B units — — — — Restricted units — — 118,731 — Diluted 21,192,714 18,442,234 16,455,602 604,137 Net (loss) income attributable to common units Basic $ (3.92) $ (3.08) $ 0.11 $ (0.82) Diluted $ (3.92) $ (3.08) $ 0.10 $ (0.82)

UNIT-BASED COMPENSATION (Tables

UNIT-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2019
UNIT-BASED COMPENSATION
Schedule of unvested restricted stock activity	Weighted Weighted Average Average Grant-Date Remaining Fair Value Contractual Units per Unit Term Unvested at December 31, 2018 1,157,924 $ 18.054 2.696 years Vesting (418,445) 18.045 — Unvested at December 31, 2019 739,479 $ 18.059 1.335 years

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
INCOME TAXES
Schedule of income tax expense	Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Current Federal $ 812,913 $ — $ — $ — State 86,512 24,681 — — Total Current 899,425 24,681 — — Deferred Federal — — — — State — — — — Total Deferred — — — — Provision for income taxes $ 899,425 $ 24,681 $ — $ —
Schedule of effective income expense	Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Net (loss) income before taxes $ (157,308,520) $ (52,257,542) $ 1,715,740 $ (496,856) Statutory rate 21 % 21 % 35 % 35 % Income tax expense computed at statutory rate (33,034,789) (10,974,084) 600,509 (173,900) Reconciling items: State income taxes 72,280 (70,441) — — Texas margins tax — 24,681 — — Change in tax status — (20,038,820) — — Non-controlling interest 18,721,170 (360,082) — — Income (loss) at OpCo 15,130,685 10,598,375 (600,509) 173,900 Change in valuation allowance - federal 80,520 20,771,214 — — Change in valuation allowance - state (70,441) 70,441 — — Other, net — 3,397 — — Provision for income taxes $ 899,425 $ 24,681 $ — $ —
Schedule of components of deferred tax assets and liabilities	Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Deferred tax asset Outside basis in OpCo $ 20,050,732 $ 21,036,307 $ — $ — Federal tax loss carryforwards — 622,775 — — State tax loss carryforwards — 70,441 — — Deferred tax asset 20,050,732 21,729,523 — — Valuation allowance (20,050,732) (20,841,655) — — Net deferred tax asset $ — $ 887,868 $ — $ — Deferred tax liability Derivative instruments and other — 887,868 — — Net deferred tax liability $ — $ 887,868 $ — $ — Reflected in the accompanying balance sheets as: Net deferred tax asset $ — $ — $ — $ — Net deferred tax liability $ — $ — $ — $ —

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2019
COMMITMENTS AND CONTINGENCIES.
Schedule of future minimum lease commitments	Years Ending December 31, 2020 $ 474,334 2021 478,428 2022 478,837 2023 480,579 2024 486,323 Thereafter 2,223,948 Total $ 4,622,449

SUPPLEMENTAL OIL AND GAS RESE_2

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2019
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Schedule of oil and natural gas aggregate capitalized costs and applicable accumulated depreciation, depletion and amortization	December 31, December 31, 2019 2018 Oil, natural gas and NGL interests Proved properties $ 758,313,233 $ 538,290,590 Unevaluated properties 275,041,784 280,304,353 Total oil, natural gas and NGL interests 1,033,355,017 818,594,943 Accumulated depreciation, depletion, accretion and impairment (328,913,425) (107,779,453) Net oil, natural gas and NGL interests capitalized $ 704,441,592 $ 710,815,490
Schedule of costs incurred in oil and natural gas activities	Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Acquisition costs Proved properties $ 104,199,579 $ 243,227,632 $ 297,609,797 $ — Unevaluated properties 110,050,000 288,334,110 — — Total 214,249,579 531,561,742 297,609,797 — Development costs Proved properties — — — — Total — — — — Total costs incurred on oil, natural gas and NGL activities $ 214,249,579 $ 531,561,742 $ 297,609,797 $ —
Results of operations from oil, natural gas and natural gas liquids	Partnership Predecessor Year Ended December 31, Period from Period from 2019 2018 2017 2017 Oil, natural gas and NGL revenues $ 107,480,446 $ 65,713,112 $ 29,943,920 $ 318,310 Lease bonus and other income 2,477,145 1,213,550 721,172 — Production and ad valorem taxes (7,719,949) (4,399,667) (2,452,058) (19,651) Depreciation and depletion expense (52,118,367) (25,213,043) (15,394,238) (113,639) Impairment of oil and natural gas properties (169,150,255) (67,311,501) — — Marketing and other deductions (8,145,397) (4,652,313) (1,648,895) (110,534) Results of operations from oil, natural gas and NGLs $ (127,176,377) $ (34,649,862) $ 11,169,901 $ 74,486
Schedule of net proved oil, natural gas and natural gas liquids reserves and changes	Crude Oil and Natural Gas Condensate Natural Gas Liquids Total (MBbls) (MMcf) (MBbls) (MBOE) Net proved reserves at January 1, 2017 7,210 50,390 1,982 17,590 Revisions of previous estimates (1) (193) (1,535) 666 217 Purchase of minerals in place (2) 362 16,312 274 3,355 Extensions, discoveries and other additions (3) 505 2,261 91 973 Production (421) (3,512) (175) (1,181) 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 (4) 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 Revisions of previous estimates (1) 849 25,398 684 5,766 Purchase of minerals in place (5) 1,787 13,129 686 4,661 Production (1,113) (17,046) (561) (4,515) Net proved reserves at December 31, 2019 12,318 148,742 6,455 43,563 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 December 31, 2019 11,303 141,181 6,079 40,912 Net proved undeveloped reserves December 31, 2017 2,179 16,415 636 5,551 December 31, 2018 1,612 10,940 583 4,018 December 31, 2019 1,015 7,561 376 2,651 (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 $29.3 million of mineral and royalty interests, the largest of which being a package in the Anadarko Basin, and also includes additional mineral and royalty interests in Texas, Louisiana, Wyoming, California, North Dakota, Utah, New Mexico, Arkansas, and Kansas. (3) Includes discoveries and additions primarily related to active drilling on the Partnership’s acreage primarily in the Permian Basin, Eagle Ford Shale. (4) 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. (5) Includes the acquisition of three packages of mineral and royalty interests for a total of $103.8 million. The first acquisition totaling $58.4 million consists of mineral and royalty interests primarily in the Eagle Ford Shale, Permian Basin, East Texas Region and Appalachia Region. The second acquisition totaling $9.4 million consists of mineral and royalty interests in the Mid-Continent Region. The third acquisition totaling $36.0 million consists of mineral and royalty interests in the Eagle Ford Shale.
Schedule of standardized measure related to proved oil, natural gas and natural gas liquids reserves	Year Ended December 31, 2019 2018 2017 Future cash inflows $ 1,025,430 $ 1,056,464 $ 562,967 Future production costs (78,061) (79,724) (45,652) Future state margin taxes (32,377) (32,885) (2,790) Future income tax expense (33,235) (41,241) — Future net cash flows 881,757 902,614 514,525 Less 10% annual discount to reflect timing of cash flows (481,786) (504,247) (298,973) Standard measure of discounted future net cash flows $ 399,971 $ 398,367 $ 215,552
Schedule of changes in standardized measure related to proved oil, natural gas and natural gas liquids reserves	Year Ended December 31, 2019 2018 2017 Standardized measure - beginning of year $ 398,367 $ 215,552 $ 159,275 Sales, net of production costs (93,942) (56,661) (29,288) Net changes of prices and production costs related to future production (72,875) 11,355 21,946 Extensions, discoveries and improved recovery, net of future production costs — — 10,064 Revisions of previous quantity estimates, net of related costs 56,666 16,385 2,248 Net changes in state margin taxes 191 (13,271) 301 Net changes in income taxes 3,752 (17,232) — Accretion of discount 42,808 21,555 15,928 Purchases of reserves in place 59,953 175,885 23,309 Timing differences and other 5,051 44,799 11,769 Standardized measure - end of year $ 399,971 $ 398,367 $ 215,552

SELECTED QUARTERLY FINANCIAL _2

SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2019
SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED
Schedule of quarterly financial data	Quarterly financial data was as follows for the periods indicated. First Quarter Second Quarter Third Quarter Fourth Quarter 2019 Total revenue $ 17,947,209 $ 31,936,601 $ 32,978,851 $ 25,362,609 Net loss attributable to common units $ (3,687,252) $ (11,758,374) $ (16,261,051) $ (51,325,605) Net loss attributable to common units Basic $ (0.21) $ (0.54) $ (0.73) $ (2.27) Diluted $ (0.21) $ (0.54) $ (0.73) $ (2.27) Cash distributions declared and paid $ 0.37 $ 0.39 $ 0.42 $ 0.38 Total assets $ 906,158,146 $ 868,725,908 $ 828,745,127 $ 748,594,054 Long-term debt $ 87,309,544 $ 87,309,544 $ 91,261,477 $ 100,135,477 Mezzanine equity $ 70,275,978 $ 71,820,563 $ 73,365,147 $ 74,909,732 Unitholders' equity $ 314,985,017 $ 360,133,072 $ 343,138,843 $ 283,827,721 Noncontrolling interest $ 427,617,585 $ 343,165,767 $ 310,744,268 $ 281,157,393 First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Total revenue $ 10,891,338 $ 10,707,898 $ 18,407,956 $ 30,251,018 Net (loss) income attributable to common units $ (52,824,471) $ 1,378,295 $ (3,711,798) $ (1,609,575) Net (loss) income attributable to common units Basic $ (3.23) $ 0.08 $ (0.15) $ (0.10) Diluted $ (3.23) $ 0.08 $ (0.15) $ (0.10) Cash distributions declared and paid $ 0.42 $ 0.43 $ 0.45 $ 0.40 Total assets $ 237,201,565 $ 249,318,570 $ 683,893,161 $ 753,285,373 Long-term debt $ 30,843,593 $ 42,972,997 $ 148,309,544 $ 87,309,544 Mezzanine equity $ — $ — $ 67,904,422 $ 69,449,006 Partners' capital / unitholders' equity $ 203,848,774 $ 198,879,415 $ 247,441,471 $ 300,794,564 Noncontrolling interest $ — $ — $ 209,450,877 $ 291,932,233

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Details)	Jul. 24, 2018$ / sharesshares	Feb. 07, 2017	Feb. 07, 2017	Dec. 31, 2019segment	Feb. 21, 2020	Dec. 31, 2016
Organization
Financial Designation, Predecessor and Successor		Predecessor	Predecessor
Percentage of future undiscounted cash flows from predecessor						11.00%
Segment Reporting
Number of operating units | segment				1
Number of reporting units | segment				1
OpCo Units
Organization
Ownership interest by Company (as a percent)					61.80%
Ownership interest by third party (as a percent)					38.20%
Haymaker Holdings | Common Units | Kimbell Royalty Operating, LLC
Organization
Number of units held by investor that were exchanged (in units)	10,000,000
Haymaker Holdings | Class B Common Units
Organization
Additional consideration paid per unit (in dollars per unit) | $ / shares	$ 0.05
Distribution rate (as a percent)	2.00%
Haymaker Holdings | Class B Common Units | Kimbell Royalty Operating, LLC
Organization
Units issued (in units)	10,000,000
Haymaker Holdings | OpCo Units | Kimbell Royalty Operating, LLC
Organization
Units issued (in units)	10,000,000
Haymaker Foundation | Common Units | Kimbell Royalty Operating, LLC
Organization
Number of units held by investor that were exchanged (in units)	2,953,258
Haymaker Foundation | Class B Common Units
Organization
Distribution rate (as a percent)	2.00%
Haymaker Foundation | Class B Common Units | Kimbell Royalty Operating, LLC
Organization
Units issued (in units)	2,953,258
Haymaker Foundation | OpCo Units | Kimbell Royalty Operating, LLC
Organization
Units issued (in units)	2,953,258
Kimbell Royalty Operating, LLC | Series A Preferred Units
Organization
Units owned in subsidiary (in units)	110,000
Kimbell Royalty Operating, LLC | Common Units
Organization
Units owned in subsidiary (in units)	13,886,204

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -Other Disclosures (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable
Allowance for doubtful accounts receivable	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2019
Minimum
Oil and natural gas properties
Useful life	3 years
Maximum
Oil and natural gas properties
Useful life	7 years

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) - USD ($)	Feb. 07, 2017	Feb. 07, 2017	Mar. 31, 2017	Feb. 28, 2017	Feb. 07, 2017	Jan. 31, 2017	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Financial Designation, Predecessor and Successor	Predecessor				Predecessor
Oil and Natural Gas Properties
Period for completion of unevaluated costs into the amortization base											5 years
Impairment of oil and natural gas properties					$ 0		$ 12,600,000	$ 54,800,000		$ 0	$ 169,150,255	$ 67,311,501
Gain (loss) recorded on disposition of oil, natural gas and natural gas liquid properties		$ 0	$ 0	$ 0		$ 0			$ 0		0	0
Number of exploratory activities pending determination		0	0	0					0		0	0
Exploratory costs charged		$ 0	$ 0	$ 0					$ 0		$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($)	Feb. 07, 2017	Feb. 07, 2017	Mar. 31, 2017	Feb. 28, 2017	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Financial Designation, Predecessor and Successor	Predecessor				Predecessor
Income Taxes
Texas franchise tax (as a percent)							0.75%
Uncertain tax positions							$ 0	$ 0
Interest and penalties		$ 0	$ 0	$ 0		$ 0	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration of Credit Risk (Details) - Sales - Customer - item	11 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Concentration of Credit Risk
Number of significant purchasers	1	1	1
Operator 1
Concentration of Credit Risk
Purchaser percentage	14.00%	6.00%	10.00%

SUMMARY OF SIGNIFICANT ACCOUN_9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue from Contracts with Customers (Details)	12 Months Ended
	Dec. 31, 2019
Minimum
Settlement period for certain natural gas and natural gas liquids sales	1 month
Maximum
Settlement period for certain natural gas and natural gas liquids sales	4 months

SUMMARY OF SIGNIFICANT ACCOU_10

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Leases (Details)	12 Months Ended
	Dec. 31, 2019USD ($)
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Operating lease weighted average remaining lease term	9 years 4 months 2 days
Operating lease weighted average discount rate (as a percent)	6.75%
Operating lease expense	$ 300,000
2020	474,334
2021	478,428
2022	478,837
2023	480,579
2024	486,323
Thereafter	2,223,948
Total operating leases	4,622,449
Less Imputed Interest	(1,243,903)
Total	$ 3,378,546
Operating lease liability	us-gaap:OtherAccruedLiabilitiesCurrent us-gaap:OperatingLeaseLiabilityNoncurrent

ACQUISITIONS, JOINT VENTURES _2

ACQUISITIONS, JOINT VENTURES AND DIVESTITURES - Acquisitions (Details)	Dec. 12, 2019ashares	Nov. 06, 2019USD ($)a	Jun. 19, 2019USD ($)	Mar. 25, 2019ashares	Dec. 20, 2018ashares	Jul. 12, 2018USD ($)ashares	Dec. 13, 2017USD ($)	Nov. 08, 2017USD ($)a	Oct. 09, 2017USD ($)a	Jun. 30, 2017USD ($)a	Dec. 31, 2019USD ($)
Acquisitions
Investments | $											$ 2,952,264
Phillips Acquisition
Acquisitions
Gross acres acquired (in acres)				866,528
Net royalty acres acquired (in acres)				12,210
Phillips Acquisition | OpCo Units
Acquisitions
Purchase price units (in units) | shares				9,400,000
Phillips Acquisition | Class B
Acquisitions
Purchase price units (in units) | shares				9,400,000
Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP.
Acquisitions
Ownership interest (as a percent)			49.30%
Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP. | Maximum
Acquisitions
Purchase price units value | $			$ 15,000,000
Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP. | Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP.
Acquisitions
Investments | $											$ 3,000,000
Oklahoma Property Acquisition
Acquisitions
Purchase price cash, gross | $		$ 9,900,000
Gross acres acquired (in acres)		279,680
Net royalty acres acquired (in acres)		186
Buckhorn Acquisition
Acquisitions
Gross acres acquired (in acres)	86,005
Net royalty acres acquired (in acres)	405
Buckhorn Acquisition | OpCo Units
Acquisitions
Purchase price units (in units) | shares	2,169,348
Buckhorn Acquisition | Class B
Acquisitions
Purchase price units (in units) | shares	2,169,348
Haymaker
Acquisitions
Transaction value of acquisition | $						$ 444,000,000
Purchase price cash, gross | $						$ 208,600,000
Purchase price units (in units) | shares						10,000,000
Gross acres acquired (in acres)						5,400,000
Net royalty acres acquired (in acres)						43,000
The Dropdown
Acquisitions
Gross acres acquired (in acres)					1,000,000
Net royalty acres acquired (in acres)					16,700
The Dropdown | OpCo Units
Acquisitions
Purchase price units (in units) | shares					6,500,000
Mineral And Royalty Interests
Acquisitions
Transaction value of acquisition | $							$ 1,300,000	$ 7,300,000	$ 3,900,000	$ 16,800,000
Gross acres acquired (in acres)								71,410	8,460	1,100,000
Net royalty acres acquired (in acres)								2,757	983	6,881

ACQUISITIONS, JOINT VENTURES _3

ACQUISITIONS, JOINT VENTURES AND DIVESTITURES - Divestitures (Details)	1 Months Ended
	May 31, 2018USD ($)aitem
ACQUISITIONS, JOINT VENTURES AND DIVESTITURES
Number of purchase and sale agreements executed | item	2
The sale price of asset | $	$ 10,600,000
Gain loss on sale | $	$ 0
Number of Boe per day sold | item	29
Boe per day sold to total Boe per day (as a percent)	0.80%
Net royalty acres land sold (in acres) | a	59
Net royalty acres land sold to total net royalty acres land (as a percent)	0.08%

DERIVATIVES (Details)

DERIVATIVES (Details)	11 Months Ended	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2019USD ($)$ / bblbblMMBbls	Dec. 31, 2018USD ($)
Derivatives
Daily oil and natural gas production (as a percent)				18.00%
Change in fair values of derivative instruments
Beginning fair value of commodity derivative instruments | $		$ 4,227,946	$ (318,829)
(Loss) gain on commodity derivative instruments, net | $	$ (318,829)	(1,732,321)	3,331,548
Net cash (received) paid on settlements of derivative instruments | $		(1,691,124)	1,215,227
Ending fair value of commodity derivative instruments | $	(318,829)	804,501	4,227,946
Assets:
Current asset | $				$ 687,933	$ 2,981,117
Long-term asset | $				116,568	1,246,829
Derivative assets (liabilities) | $	$ (318,829)	$ 804,501	$ 4,227,946	$ 804,501	$ 4,227,946
Oil Price Swaps - December 2019
Derivatives
Notional Volumes | bbl				19,034
Weighted Average Fixed Price				61.47
Oil Price Swaps - January 2020 - December 2020
Derivatives
Notional Volumes | bbl				224,356
Weighted Average Fixed Price				55.48
Oil Price Swaps - January 2021 - December 2021
Derivatives
Notional Volumes | bbl				238,307
Weighted Average Fixed Price				53.49
Natural Gas Price Swaps - January 2020 - December 2020
Derivatives
Notional Volumes | MMBbls				3,582,862
Weighted Average Fixed Price				2.64
Natural Gas Price Swaps - January 2021 - December 2021
Derivatives
Notional Volumes | MMBbls				3,503,617
Weighted Average Fixed Price				2.49
Minimum | Oil Price Swaps - December 2019
Derivatives
Weighted Average Fixed Price				53.07
Minimum | Oil Price Swaps - January 2020 - December 2020
Derivatives
Weighted Average Fixed Price				50.45
Minimum | Oil Price Swaps - January 2021 - December 2021
Derivatives
Weighted Average Fixed Price				50.79
Minimum | Natural Gas Price Swaps - January 2020 - December 2020
Derivatives
Weighted Average Fixed Price				2.51
Minimum | Natural Gas Price Swaps - January 2021 - December 2021
Derivatives
Weighted Average Fixed Price				2.33
Maximum | Oil Price Swaps - December 2019
Derivatives
Weighted Average Fixed Price				63.47
Maximum | Oil Price Swaps - January 2020 - December 2020
Derivatives
Weighted Average Fixed Price				61.43
Maximum | Oil Price Swaps - January 2021 - December 2021
Derivatives
Weighted Average Fixed Price				56.10
Maximum | Natural Gas Price Swaps - January 2020 - December 2020
Derivatives
Weighted Average Fixed Price				2.94
Maximum | Natural Gas Price Swaps - January 2021 - December 2021
Derivatives
Weighted Average Fixed Price				2.85

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - Commodity Contract - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative contracts	$ 804,501	$ 4,227,946
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative contracts	$ 804,501	$ 4,227,946

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES (Details)	Feb. 07, 2017	Feb. 07, 2017USD ($)	Dec. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019USD ($)$ / Mcf	Dec. 31, 2019USD ($)$ / bbl	Dec. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)$ / Mcf	Dec. 31, 2018USD ($)$ / bbl	Dec. 31, 2018USD ($)	Dec. 31, 2017$ / bbl
Oil and natural gas properties
Financial Designation, Predecessor and Successor	Predecessor	Predecessor
Proved properties			$ 538,290,590			$ 758,313,233	$ 758,313,233	$ 758,313,233	$ 758,313,233	$ 758,313,233	$ 538,290,590	$ 538,290,590	$ 538,290,590
Unevaluated properties			280,304,353			275,041,784	275,041,784	275,041,784	275,041,784	275,041,784	280,304,353	280,304,353	280,304,353
Less: accumulated depreciation, depletion, and impairment			(107,779,453)			(328,913,425)	(328,913,425)	(328,913,425)	(328,913,425)	(328,913,425)	(107,779,453)	(107,779,453)	(107,779,453)
Total oil and natural gas properties, net			710,815,490			$ 704,441,592	$ 704,441,592	$ 704,441,592	$ 704,441,592	704,441,592	$ 710,815,490	$ 710,815,490	710,815,490
Useful life						5 years
Impairment of oil and natural gas properties		$ 0	$ 12,600,000	$ 54,800,000	$ 0					$ 169,150,255			$ 67,311,501
Crude Oil and Condensate
Oil and natural gas properties
Average sales prices | $ / bbl								55.69				65.56		51.34
Average sales price change (in percent)									15.10%
Natural Gas
Oil and natural gas properties
Average sales prices							2.58	2.58			3.10	3.10		2.980
Average sales price change (in percent)									16.80%

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($)	Jul. 12, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	May 31, 2019	Jul. 11, 2018	Feb. 08, 2017
Long-term debt
Borrowings of debt		$ 30,843,593	$ 12,825,933	$ 124,336,547
Repayment of debt				$ 67,870,596
Revolving credit facility
Long-term debt
Revolving credit facility maximum borrowings	$ 200,000,000				$ 225,000,000	$ 50,000,000
Revolving credit facility increased maximum borrowing capacity if certain conditions are met	500,000,000
Revolving credit facility outstanding			$ 100,100,000
Interest rate on outstanding borrowings (as a percent)			4.58%
Borrowing base	$ 200,000,000				$ 300,000,000
Amount of applicable margin decrease for each applicable level (as a percent)	0.25%
Borrowings of debt			$ 12,800,000
Revolving credit facility | LIBOR
Long-term debt
Variable rate			LIBOR
Margin (as a percent)			2.25%
Revolving credit facility | Prime
Long-term debt
Variable rate			Prime Rate
Margin (as a percent)			1.25%
Revolving credit facility | Maximum
Long-term debt
Debt to EBITDAX ratio							400.00%
Revolving credit facility | Maximum | LIBOR
Long-term debt
Margin (as a percent)	3.00%
Revolving credit facility | Maximum | Prime
Long-term debt
Margin (as a percent)	2.00%
Revolving credit facility | Minimum
Long-term debt
Debt to EBITDAX ratio							100.00%
Revolving credit facility | Minimum | LIBOR
Long-term debt
Margin (as a percent)	2.00%
Revolving credit facility | Minimum | Prime
Long-term debt
Margin (as a percent)	1.00%

PREFERRED UNITS - Other (Detail

PREFERRED UNITS - Other (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jul. 31, 2018	Dec. 31, 2019
Preferred units
The period after issuance securities become convertible	2 years
Discount rate to the issue price (as a percent)	$ 30
Percent of redemption price exceeding invested capital for the Partnership to initiate redemption (as a percent)	120.00%
Minimum IRR prior to the fifth anniversary of Series A Issuance Date (as a percent)		13.00%
Minimum IRR on or after the fifth anniversary of Series A Issuance Date (as a percent)		14.00%
Minimum IRR on or after the sixth anniversary of Series A Issuance Date (as a percent)		15.00%
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Units
Preferred units
Series A preferred units issued	110,000
Share price (in dollars per unit)	$ 1,000
Proceeds from the issuance of preferred units	$ 110,000,000
Distribution rate (as a percent)	7.00%

PREFERRED UNITS - Rollforward (

PREFERRED UNITS - Rollforward (Details) - shares	Dec. 31, 2019	Dec. 31, 2018
Series A Preferred Units
Preferred units
Balance	110,000	110,000

UNITHOLDERS' EQUITY AND PARTN_3

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Details) - $ / shares	3 Months Ended												12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Common units
Units issued (in units)														23,518,652	18,056,487
Units outstanding (in units)	23,518,652			18,056,487	18,056,487								23,518,652	23,518,652	18,056,487
Capital rollforward
Unitholders' capital, beginning balance (in units)				18,056,487									18,056,487
Unitholders' capital, ending balance (in units)	23,518,652				18,056,487								23,518,652
Cash distributions declared and paid (in dollars per unit)	$ 0.38	$ 0.42	$ 0.39	$ 0.37	$ 0.40	$ 0.45	$ 0.43	$ 0.42	$ 0.36	$ 0.31	$ 0.30	$ 0.23
Common Units
Common units
Units issued (in units)														23,518,652
Units outstanding (in units)	23,518,652			18,056,487	18,056,487								23,518,652	23,518,652	18,056,487
Capital rollforward
Unitholders' capital, beginning balance (in units)				18,056,487									18,056,487
Conversion of Class B Units (in units)													5,465,000
Restricted units used for tax withholding (in units)													(2,835)
Unitholders' capital, ending balance (in units)	23,518,652				18,056,487								23,518,652
Class B
Common units
Units outstanding (in units)	25,557,606			19,453,258	19,453,258								25,557,606	25,557,606	19,453,258
Capital rollforward
Unitholders' capital, beginning balance (in units)				19,453,258									19,453,258
Conversion of Class B Units (in units)													(5,465,000)
Restricted units used for tax withholding (in units)													25,557,606
Unitholders' capital, ending balance (in units)	25,557,606				19,453,258								25,557,606
Cash distributions (as a percent)													2.00%
Phillips Acquisition | Class B
Capital rollforward
Units issued to acquisition (in units)													11,569,348

EARNINGS (LOSS) PER UNIT (Detai

EARNINGS (LOSS) PER UNIT (Details) - USD ($)	Feb. 07, 2017	Feb. 07, 2017	Feb. 07, 2017	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Earnings per unit
Financial Designation, Predecessor and Successor	Predecessor		Predecessor
Net (loss) income attributable to common units			$ (496,856)									$ 1,715,740	$ (83,032,282)	$ (56,767,549)
Weighted average number of common units outstanding Basic (in units)												16,336,871	21,192,714	18,442,234
Weighted average number of common units outstanding Basic (in units)			604,137
Weighted average number of common units outstanding Diluted (in units)												16,455,602	21,192,714	18,442,234
Weighted Average Number of Shares Outstanding, Diluted, Total			604,137
Net (loss) income attributable to common units per unit (basic)				$ (2.27)	$ (0.73)	$ (0.54)	$ (0.21)	$ (0.10)	$ (0.15)	$ 0.08	$ (3.23)	$ 0.11	$ (3.92)	$ (3.08)
Net (loss) income attributable to common units per unit (basic)			$ (0.82)
Net (loss) income attributable to common units per unit (diluted)				$ (2.27)	$ (0.73)	$ (0.54)	$ (0.21)	$ (0.10)	$ (0.15)	$ 0.08	$ (3.23)	$ 0.10	$ (3.92)	$ (3.08)
Net (loss) income attributable to common units per unit (diluted)			$ (0.82)
Options
Earnings per unit
Anti-dilutive options outstanding		110,000
Restricted Units
Earnings per unit
Weighted average number of common units outstanding (in units)												118,731
Anti-dilutive options outstanding													739,479	1,157,924

UNIT-BASED COMPENSATION (Detail

UNIT-BASED COMPENSATION (Details) - USD ($)	Sep. 23, 2018	Feb. 07, 2017	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Unit-based compensation
Financial Designation, Predecessor and Successor		Predecessor	Predecessor
Share-based compensation			$ 50,422	$ 798,413	$ 7,502,678	$ 3,170,299
Restricted Units
Unvested Units
Unvested at beginning of period (in units)					1,157,924
Vesting (in units)					(418,445)
Unvested at end of period (in units)					739,479	1,157,924
Unvested Weighted Average Grant-Date Fair Value
Unvested at beginning of period (in dollars per unit)					$ 18.054
Vesting (in dollars per unit)					18.045
Unvested at end of period (in dollars per unit)					$ 18.059	$ 18.054
Weighted Average Remaining Contractual Term
Unvested contractual term, at end of period					1 year 4 months 1 day	2 years 8 months 11 days
Long-Term Incentive Plan
Unit-based compensation
Additional common units authorized for issuance	2,500,000
Vesting period					3 years
Authorized issuance of units	4,541,600	110,000	110,000
Share-based compensation			$ 50,000
Long-Term Incentive Plan | First Anniversary
Unit-based compensation
Vesting percent					33.30%
Long-Term Incentive Plan | Second Anniversary
Unit-based compensation
Vesting percent					33.30%
Long-Term Incentive Plan | Third Anniversary
Unit-based compensation
Vesting percent					33.30%

INCOME TAXES - (Details)

INCOME TAXES - (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
INCOME TAXES
Effective income tax rate (as a percent)	(0.60%)
Federal tax loss carryforwards		$ 622,775
State tax loss carryforwards		$ 70,441

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Current
Federal	$ 812,913
State	86,512	$ 24,681
Total Current	899,425	24,681
Deferred
Provision for income taxes	$ 899,425	$ 24,681

INCOME TAXES - Reconciliation (

INCOME TAXES - Reconciliation (Details) - USD ($)	Feb. 07, 2017	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
INCOME TAXES
Financial Designation, Predecessor and Successor	Predecessor	Predecessor
Reconciliation of the provision for income taxes at statutory rates to the provision for income taxes at the effective tax rate
Net (loss) income before taxes		$ (496,856)	$ 1,715,740	$ (157,308,520)	$ (52,257,542)
Statutory rate (as a percent)		35.00%	35.00%	21.00%	21.00%
Income tax expense computed at statutory rate		$ (173,900)	$ 600,509	$ (33,034,789)	$ (10,974,084)
State income taxes				72,280	(70,441)
Texas margins tax					24,681
Change in tax status					(20,038,820)
Non-controlling interest				18,721,170	(360,082)
Income (loss)		$ 173,900	$ (600,509)	15,130,685	10,598,375
Change in valuation allowance - federal				80,520	20,771,214
Change in valuation allowance - state				(70,441)	70,441
Other, net					3,397
Provision for income taxes				$ 899,425	$ 24,681

INCOME TAXES - Deferred Taxes (

INCOME TAXES - Deferred Taxes (Details) - USD ($)	Feb. 07, 2017	Feb. 07, 2017	Dec. 31, 2019	Dec. 31, 2018
INCOME TAXES
Financial Designation, Predecessor and Successor	Predecessor	Predecessor
Deferred tax asset
Outside basis in OpCo			$ 20,050,732	$ 21,036,307
Federal tax loss carryforwards				622,775
State tax loss carryforwards				70,441
Deferred tax assets			20,050,732	21,729,523
Valuation allowance			(20,050,732)	(20,841,655)
Net deferred tax assets				887,868
Deferred tax liability
Derivative instruments and other				887,868
Net deferred tax liability				887,868
Outside basis investment in operating company valuation allowance			20,100,000
Uncertain tax positions			$ 0	$ 0

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Related Party Transactions
Outstanding receivable from Rivercrest Capital Management and certain employees		$ 7,773
BJF Royalties
Related Party Transactions
Payments made to related parties	$ 0
Steward Royalties
Related Party Transactions
Payments made to related parties	0
Taylor Companies
Related Party Transactions
Payments made to related parties	526,855
K3 Royalties
Related Party Transactions
Payments made to related parties	120,000
Nail Bay Royalties
Related Party Transactions
Payments made to related parties	327,671
Duncan Management
Related Party Transactions
Payments made to related parties	$ 498,306

ADMINISTRATIVE SERVICES (Detail

ADMINISTRATIVE SERVICES (Details)	2 Months Ended
	May 31, 2019USD ($)
Phillips Acquisition
Transition service fees incurred	$ 300,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) - USD ($)	1 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
COMMITMENTS AND CONTINGENCIES.
2020				$ 474,334
2021				478,428
2022				478,837
2023				480,579
2024				486,323
Thereafter				2,223,948
Total operating leases				4,622,449
Operating Lease, Expense				$ 300,000
Operating Leases, Rent Expense	$ 100,000	$ 100,000	$ 100,000		$ 100,000

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($)	Feb. 12, 2020	Feb. 06, 2020	Feb. 05, 2020	Jan. 28, 2020	Jan. 27, 2020	Jan. 24, 2020	Jan. 09, 2020	Jan. 31, 2020	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Subsequent events
Repayment of debt											$ 67,870,596
Common units issued									$ 103,500,000		61,411,708
Distributions on Series A redeemable preferred units										$ 7,700,000	$ 2,630,834
Class B Common Units
Subsequent events
Distribution Made to Limited Liability Company (LLC) Member, Cash Distributions Paid										$ 24,808
Subsequent Event
Subsequent events
Joint Venture contributions								$ 800,000
Repayment of debt								70,000,000
Distributions on Series A redeemable preferred units			$ 1,900,000
Subsequent Event | OpCo Units
Subsequent events
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit		$ 0.387662
Tax payment made from cash reserves per unit		$ 0.007662
Subsequent Event | Class B Common Units
Subsequent events
Percentage Of Respective Class Contribution Made		2.00%
Subsequent Event | Common Units
Subsequent events
Cash distributions declared (in dollars per unit)						$ 0.38
Subsequent Event | Series A Preferred Units
Subsequent events
Units redeemed	55,000
Percentage of units redeemed	50.00%
Redemption price per share	$ 1,110.72
Aggregate redemption price	$ 61,100,000
Subsequent Event | Springbok Acquisition
Subsequent events
Cash consideration							$ 95,000,000
Deposit on purchase price							$ 9,500,000
Subsequent Event | Springbok I Sellers | Common Units
Subsequent events
Business Acquisition issuance of common units							2,224,358
Subsequent Event | Springbok II Sellers | Class Operating Company Common Units And Class B Units [Member]
Subsequent events
Business Acquisition issuance of common units							2,497,133
EIGF Aggregator III LLC [Member] | Subsequent Event | Class Operating Company Common Units And Class B Units [Member]
Subsequent events
Number of units exchanged to common units				3,897,483	702,071
TE Drilling Aggregator LLC [Member] | Subsequent Event | Class Operating Company Common Units And Class B Units [Member]
Subsequent events
Number of units exchanged to common units				266,076	47,929
Underwritten Public Offering | Subsequent Event
Subsequent events
Common units issued								5,000,000
Proceeds from Issuance of Common Limited Partners Units								74,000,000
Underwriters option to purchase additional units | Subsequent Event
Subsequent events
Common units issued								$ 750,000

SUPPLEMENTAL OIL AND GAS RESE_3

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Other Disclosures (Details)	Feb. 07, 2017	Feb. 07, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)segment	Dec. 31, 2018USD ($)
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Financial Designation, Predecessor and Successor	Predecessor	Predecessor
Number of reporting segments | segment				1
Oil, natural gas and NGL interests
Proved properties				$ 758,313,233	$ 538,290,590
Unevaluated properties				275,041,784	280,304,353
Total oil, natural gas and NGL interest				1,033,355,017	818,594,943
Accumulated depreciation, depletion and impairment				(328,913,425)	(107,779,453)
Net oil, natural gas and NGL interests capitalized				704,441,592	710,815,490
Acquisition costs
Proved properties			$ 297,609,797	104,199,579	243,227,632
Unevaluated properties				110,050,000	288,334,110
Total			297,609,797	214,249,579	531,561,742
Developed costs
Total costs incurred on oil, natural gas and NGL activities			297,609,797	214,249,579	531,561,742
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities
Oil, natural gas and NGL revenue		$ 318,310	29,943,920	107,480,446	65,713,112
Lease bonus and other income			721,172	2,477,145	1,213,550
Production and ad valorem taxes		(19,651)	(2,452,058)	(7,719,949)	(4,399,667)
Depreciation and depletion expense		(113,639)	(15,394,238)	(52,118,367)	(25,213,043)
Impairment of oil and natural properties				(169,150,255)	(67,311,501)
Marketing and other deductions		(110,534)	(1,648,895)	(8,145,397)	(4,652,313)
Results of operations form oil, natural gas and NGLs		$ 74,486	$ 11,169,901	$ (127,176,377)	$ (34,649,862)

SUPPLEMENTAL OIL AND GAS RESE_4

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Proved Oil, Natural Gas and Natural Liquids Reserve Quantities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)itemMMcfMBbls	Dec. 31, 2018USD ($)itemMMcfMBbls	Dec. 31, 2017USD ($)MMcfMBbls
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	37,651	20,954	17,590
Revisions of previous estimates	5,766	1,437	217
Purchase of minerals in place	4,661	17,473	3,355
Extensions, discoveries and other additions			973
Production	(4,515)	(2,213)	(1,181)
Net proved reserves at end of period	43,563	37,651	20,954
Net Proved Developed Reserves	40,912	33,633	15,403
Net Proved Undeveloped Reserves	2,651	4,018	5,551
Crude Oil and Condensate
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	10,795	7,463	7,210
Revisions of previous estimates	849	194	(193)
Purchase of minerals in place	1,787	3,729	362
Extensions, discoveries and other additions			505
Production	(1,113)	(591)	(421)
Net proved reserves at end of period	12,318	10,795	7,463
Net Proved Developed Reserves	11,303	9,183	5,284
Net Proved Undeveloped Reserves	1,015	1,612	2,179
Natural Gas
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period | MMcf	127,261	63,916	50,390
Revisions of previous estimates | MMcf	25,398	1,754	(1,535)
Purchase of minerals in place | MMcf	13,129	69,465	16,312
Extensions, discoveries and other additions | MMcf			2,261
Production | MMcf	(17,046)	(7,874)	(3,512)
Net proved reserves at end of period | MMcf	148,742	127,261	63,916
Net Proved Developed Reserves | MMcf	141,181	116,321	47,501
Net Proved Undeveloped Reserves | MMcf	7,561	10,940	16,415
Natural Gas Liquids
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	5,646	2,838	1,982
Revisions of previous estimates	684	952	666
Purchase of minerals in place	686	2,166	274
Extensions, discoveries and other additions			91
Production	(561)	(310)	(175)
Net proved reserves at end of period	6,455	5,646	2,838
Net Proved Developed Reserves	6,079	5,063	2,202
Net Proved Undeveloped Reserves	376	583	636
Mineral And Royalty Interests
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $			$ 29.3
Permian Basis, Haynesville Shale, Mid-Continent Area, Appalachia Region and Eagle Ford Shale
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $	$ 103.8	$ 243.2
Number of packages of diverse mineral and royalty interests acquired | item	3	2
Permian Basin, Haynesville Shale, Mid Continent Area and Appalachia Region
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $		$ 155.7
Permian Basin, Eagle Ford Shale and Appalachia Region
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $		$ 87.5
Permian Basin And Eagle Ford Shale And East Texas Region And Appalachia Region [Member]
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $	$ 58.4
Permian Basin Mid-Continent Region [Member]
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $	9.4
Permian Basin And Eagle Ford Shale Region [Member]
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $	$ 36

SUPPLEMENTAL OIL AND GAS RESE_5

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Standardized Measure (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Standardized Measure
Future cash inflows	$ 1,025,430	$ 1,056,464	$ 562,967
Future production costs	(78,061)	(79,724)	(45,652)
Future state margin taxes	(32,377)	(32,885)	(2,790)
Future income tax expense	(33,235)	(41,241)
Future net cash flows	881,757	902,614	514,525
Less 10% annual discount to reflect timing of cash flows	(481,786)	(504,247)	(298,973)
Standard measure of discounted future net cash flows	$ 399,971	$ 398,367	$ 215,552	$ 159,275

SUPPLEMENTAL OIL AND GAS RESE_6

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Average Market Prices (Details)	12 Months Ended
	Dec. 31, 2019$ / Mcf	Dec. 31, 2019$ / bbl	Dec. 31, 2018$ / Mcf	Dec. 31, 2018$ / bbl	Dec. 31, 2017$ / bbl
Crude Oil and Condensate
Average Sales Prices
Average sales prices		55.69		65.56	51.34
Natural Gas
Average Sales Prices
Average sales prices	2.58	2.58	3.10	3.10	2.980

SUPPLEMENTAL OIL AND GAS RESE_7

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Changes in Standardized Measure (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in Standardized Measure
Standardized measure - beginning of year	$ 398,367	$ 215,552	$ 159,275
Sales, net of production costs	(93,942)	(56,661)	(29,288)
Net changes of prices and production costs related to future production	(72,875)	11,355	21,946
Extensions, discoveries and improved recovery, net of future production costs			10,064
Revisions of previous quantity estimates, net of related costs	56,666	16,385	2,248
Net changes in state margin taxes	191	(13,271)	301
Net changes in income taxes	3,752	(17,232)
Accretion of discount	42,808	21,555	15,928
Purchases of reserves in place	59,953	175,885	23,309
Timing differences and other	5,051	44,799	11,769
Standardized measure - end of year	$ 399,971	$ 398,367	$ 215,552

SELECTED QUARTERLY FINANCIAL _3

SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED (Details) - USD ($)	3 Months Ended												11 Months Ended	12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED
Total revenue	$ 25,362,609	$ 32,978,851	$ 31,936,601	$ 17,947,209	$ 30,251,018	$ 18,407,956	$ 10,707,898	$ 10,891,338
Net (loss) income attributable to common units	$ (51,325,605)	$ (16,261,051)	$ (11,758,374)	$ (3,687,252)	$ (1,609,575)	$ (3,711,798)	$ 1,378,295	$ (52,824,471)
Net loss attributable to common units per unit (basic) (in dollar per share)	$ (2.27)	$ (0.73)	$ (0.54)	$ (0.21)	$ (0.10)	$ (0.15)	$ 0.08	$ (3.23)					$ 0.11	$ (3.92)	$ (3.08)
Net loss attributable to common units per unit (diluted) (in dollar per share)	(2.27)	(0.73)	(0.54)	(0.21)	(0.10)	(0.15)	0.08	(3.23)					$ 0.10	$ (3.92)	$ (3.08)
Cash distributions declared and paid (in dollars per unit)	$ 0.38	$ 0.42	$ 0.39	$ 0.37	$ 0.40	$ 0.45	$ 0.43	$ 0.42	$ 0.36	$ 0.31	$ 0.30	$ 0.23
Total assets	$ 748,594,054	$ 828,745,127	$ 868,725,908	$ 906,158,146	$ 753,285,373	$ 683,893,161	$ 249,318,570	$ 237,201,565						$ 748,594,054	$ 753,285,373
Long-term debt	100,135,477	91,261,477	87,309,544	87,309,544	87,309,544	148,309,544	42,972,997	30,843,593						100,135,477	87,309,544
Mezzanine equity	74,909,732	73,365,147	71,820,563	70,275,978	69,449,006	67,904,422								74,909,732	69,449,006
Partners' capital/unitholder's equity	283,827,721	343,138,843	360,133,072	314,985,017	300,794,564	247,441,471	$ 198,879,415	$ 203,848,774						283,827,721	300,794,564
Noncontrolling interest	$ 281,157,393	$ 310,744,268	$ 343,165,767	$ 427,617,585	$ 291,932,233	$ 209,450,877								$ 281,157,393	$ 291,932,233