Kimbell Royalty Partners (KRP) 10-K 25 Feb 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Feb. 18, 2022	Jun. 30, 2021
Document Information
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Document Transition Report	false
Entity Registrant Name	Kimbell Royalty Partners, LP
Entity File Number	001-38005
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-5505475
Entity Address, Address Line One	777 Taylor Street, Suite 810
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	945-9700
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	KRP
Security Exchange Name	NYSE
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			$ 630.7
Entity Small Business	false
Entity Emerging Growth Company	true
Entity Ex Transition Period	true
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Central Index Key	0001657788
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Amendment Flag	false
Auditor Name	GRANT THORNTON LLP
Auditor Firm ID	248
Auditor Location	Dallas, Texas
Common Units
Document Information
Entity Common Stock, Shares Outstanding		47,161,782
Class B
Document Information
Entity Common Stock, Shares Outstanding		17,611,579

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents	$ 7,052,414	$ 9,804,977
Oil, natural gas and NGL receivables	35,147,145	17,552,756
Derivative assets	166,307
Accounts receivable and other current assets	3,051,593	973,956
Total current assets	45,417,459	28,331,689
Property and equipment, net	1,888,247	1,964,660
Investment in affiliate (equity method)	4,738,822	5,134,951
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($153,284,173 and $225,681,626 excluded from depletion at December 31, 2021 and 2020, respectively)	1,204,395,484	1,149,095,232
Less: accumulated depreciation, depletion and impairment	(663,603,142)	(628,102,279)
Total oil and natural gas properties, net	540,792,342	520,992,953
Right-of-use assets, net	2,844,997	3,123,454
Derivative assets	1,590,501
Loan origination costs, net	4,214,484	5,086,486
Total assets	601,486,852	564,634,193
Current liabilities
Accounts payable	811,019	888,735
Other current liabilities	3,319,495	4,765,161
Derivative liabilities	24,190,678	3,113,178
Total current liabilities	28,321,192	8,767,074
Operating lease liabilities, excluding current portion	2,561,274	2,848,452
Derivative liabilities	4,190,776	3,167,685
Long-term debt	217,115,911	171,550,142
Other liabilities	447,918
Total liabilities	252,637,071	186,333,353
Commitments and contingencies (Note 15)
Mezzanine equity:
Series A preferred units (0 and 55,000 units issued and outstanding as of December 31, 2021 and 2020, respectively)		42,666,102
Unitholders' equity:
Common units (47,162,773 units and 38,918,689 units issued and outstanding as of December 31, 2021 and 2020, respectively)	328,717,841	257,593,307
Class B units (17,611,579 and 20,779,781 units issued and outstanding as of December 31, 2021 and 2020, respectively)	880,579	1,038,989
Total unitholders' equity	329,598,420	258,632,296
Noncontrolling interest	19,251,361	77,002,442
Total equity	348,849,781	335,634,738
Total liabilities, mezzanine equity and unitholders' equity	$ 601,486,852	$ 564,634,193

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
CONSOLIDATED BALANCE SHEETS
Oil and natural gas properties excluded from depletion	$ 153,284,173	$ 225,681,626
Temporary equity, issued (in units)	0	55,000
Temporary equity, outstanding (in units)	0	55,000
Common units, issued (in units)	47,162,773	38,918,689
Common units, outstanding (in units)	47,162,773	38,918,689
Class B units, issued (in units)	17,611,579	20,779,781
Class B units, outstanding (in units)	17,611,579	20,779,781

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Loss on commodity derivative instruments, net	$ (42,791,909)	$ (2,450,541)	$ (1,732,321)
Total revenues	135,615,216	90,481,915	108,225,270
Costs and expenses
Production and ad valorem taxes	10,480,481	6,389,231	7,719,949
Depreciation and depletion expense	36,797,881	47,988,796	52,118,367
Impairment of oil and natural gas properties	0	251,558,557	169,150,255
Marketing and other deductions	12,048,643	9,376,375	8,145,397
General and administrative expense	26,977,519	25,902,496	22,666,601
Total costs and expenses	86,304,524	341,215,455	259,800,569
Operating income (loss)	49,310,692	(250,733,540)	(151,575,299)
Other income (expense)
Equity income in affiliate	1,119,819	763,988	80,481
Interest expense	(9,182,103)	(6,430,061)	(5,813,702)
Loss on extinguishment of debt		(476,350)
Other income (expense)	1,263,566	(100,000)
Net income (loss) before income taxes	42,511,974	(256,975,963)	(157,308,520)
Provision for (benefit from) income taxes	74,100	(885,193)	899,425
Net income (loss)	42,437,874	(256,090,770)	(158,207,945)
Distribution and accretion on Series A preferred units	(11,249,969)	(7,810,588)	(13,878,336)
Net income (loss) and distributions and accretion on Series A preferred units attributable to noncontrolling interests	(8,496,104)	96,642,334	89,148,428
Distribution on Class B units	(76,780)	(91,869)	(94,429)
Net income (loss) attributable to common units	$ 22,615,021	$ (167,350,893)	$ (83,032,282)
Net income (loss) attributable to common units
Net income (loss) attributable to common units (basic) (in dollar per share)	$ 0.56	$ (4.85)	$ (3.92)
Net income (loss) attributable to common units (diluted) (in dollar per share)	$ 0.51	$ (4.85)	$ (3.92)
Weighted average number of common units outstanding
Weighted average number of common units outstanding Basic (in units)	40,400,907	34,530,398	21,192,714
Weighted average number of common units outstanding Diluted (in units)	60,957,824	34,530,398	21,192,714
Oil, natural gas and NGL revenues
Revenue	$ 175,088,021	$ 92,586,685	$ 107,480,446
Lease bonus and other income
Revenue	$ 3,319,104	$ 345,771	$ 2,477,145

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY - USD ($)	Common Units	Class B Common Units	Non Controlling Interest	Total
Unitholders' capital, beginning balance at Dec. 31, 2018	$ 299,821,901	$ 972,663	$ 291,932,233	$ 592,726,797
Unitholders' capital, beginning balance (in units) at Dec. 31, 2018	18,056,487	19,453,258
Increase (Decrease) in Unitholders' Capital
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)
Restricted units repurchased for tax withholding	$ (46,280)			(46,280)
Restricted units repurchased for tax withholding (in units)	(2,835)
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
Unit-based compensation	$ 7,502,678			7,502,678
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	(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
Increase (Decrease) in Unitholders' Capital
Units issued for Acquisition	$ 13,257,174	$ 124,857	14,758,062	28,140,093
Units issued for Acquisition (in units)	2,224,358	2,497,134
Common units issued for equity offering	$ 73,601,668			73,601,668
Common units issued for equity offering (in units)	5,000,000
Conversion of Class B units to common units	$ 92,065,325	$ (363,748)	(92,065,325)	(363,748)
Conversion of Class B units to common units (in units)	7,274,959	(7,274,959)
Redemption of Series A preferred units	$ (16,150,018)		(9,697,873)	(25,847,891)
Restricted units repurchased for tax withholding	$ (273,244)			(273,244)
Restricted units repurchased for tax withholding (in units)	(29,181)
Forfeiture of restricted units	$ (127,934)			(127,934)
Forfeiture of restricted units (in units)	(16,737)
Unit-based compensation	$ 9,535,000			9,535,000
Unit-based compensation (in units)	946,638
Distributions to unitholders	$ (29,513,612)		(20,507,481)	(50,021,093)
Distribution and accretion on Series A preferred units	(4,946,646)		(2,863,942)	(7,810,588)
Distribution on Class B units	(91,869)			(91,869)
Net loss	(162,312,378)		(93,778,392)	(256,090,770)
Unitholders' capital, ending balance at Dec. 31, 2020	$ 257,593,307	$ 1,038,989	77,002,442	$ 335,634,738
Unitholders' capital, ending balance (in units) at Dec. 31, 2020	38,918,689	20,779,781		38,918,689
Increase (Decrease) in Unitholders' Capital
Common units issued for equity offering	$ 57,522,440			$ 57,522,440
Common units issued for equity offering (in units)	4,312,500
Conversion of Class B units to common units	$ 40,482,756	$ (158,410)	(40,482,756)	(158,410)
Conversion of Class B units to common units (in units)	3,168,202	(3,168,202)
Redemption of Series A preferred units	$ (10,753,930)		(4,229,854)	(14,983,784)
Restricted units repurchased for tax withholding	$ (2,064,693)			(2,064,693)
Restricted units repurchased for tax withholding (in units)	(173,185)
Unit-based compensation	$ 10,632,725			10,632,725
Unit-based compensation (in units)	936,567
Distributions to unitholders	$ (47,309,785)		(21,534,575)	(68,844,360)
Distribution and accretion on Series A preferred units	(7,956,092)		(3,293,877)	(11,249,969)
Distribution on Class B units	(76,780)			(76,780)
Net loss	30,647,893		11,789,981	42,437,874
Unitholders' capital, ending balance at Dec. 31, 2021	$ 328,717,841	$ 880,579	$ 19,251,361	$ 348,849,781
Unitholders' capital, ending balance (in units) at Dec. 31, 2021	47,162,773	17,611,579		47,162,773

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 42,437,874	$ (256,090,770)	$ (158,207,945)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and depletion expense	36,797,881	47,988,796	52,118,367
Impairment of oil and natural gas properties	0	251,558,557	169,150,255
Amortization of right-of-use assets	298,093	276,180	154,525
Amortization of loan origination costs	1,556,769	1,108,685	1,050,278
Loss on extinguishment of debt		476,350
Equity income in affiliate	(1,119,819)	(763,988)	(80,481)
Cash distribution from affiliate	1,015,559	812,810
Forfeiture of restricted units		(127,934)
Unit-based compensation	10,632,725	9,261,756	7,502,678
Loss on derivative instruments, net of settlements	20,343,783	7,085,364	3,423,445
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables	(17,594,389)	1,618,006	4,410,140
Accounts receivable and other current assets	(2,077,637)	(897,088)	(26,317)
Accounts payable	(77,716)	(319,001)	(125,387)
Other current liabilities	(463,828)	533,582	1,762,633
Operating lease liabilities	(306,814)	(275,964)	(429,743)
Net cash provided by operating activities	91,442,481	62,245,341	80,702,448
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment	(772,688)	(996,102)	(1,032,105)
Purchase of oil and natural gas properties	(55,300,252)	(87,600,123)	(11,686,570)
Investment in affiliate		(2,231,509)	(2,965,933)
Cash distribution from affiliate	500,389		94,150
Net cash used in investing activities	(55,572,551)	(90,827,734)	(15,590,458)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity offering	57,522,440	73,601,668
Contributions from Class B unitholders			470,000
Redemption of Class B contributions on converted units	(158,410)	(363,748)	(273,250)
Issuance costs paid on Series A preferred units			(717,612)
Redemption on Series A preferred units	(67,081,680)	(61,089,600)
Distributions to common unitholders	(47,309,785)	(29,513,612)	(35,384,665)
Distribution to OpCo unitholders	(21,534,575)	(20,507,481)	(35,672,648)
Distribution and accretion on Series A preferred units	(2,800,012)	(4,812,509)	(7,700,000)
Distribution on Class B units	(76,780)	(91,869)	(94,429)
Borrowings on long-term debt	136,565,769	162,614,665	12,825,933
Repayments on long-term debt	(91,000,000)	(91,200,000)
Payment of loan origination costs	(684,767)	(4,454,394)	(88,777)
Restricted units repurchased for tax withholding	(2,064,693)		(46,279)
Net cash (used in) provided by financing activities	(38,622,493)	24,183,120	(66,681,727)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(2,752,563)	(4,399,273)	(1,569,737)
CASH AND CASH EQUIVALENTS, beginning of period	9,804,977	14,204,250	15,773,987
CASH AND CASH EQUIVALENTS, end of period	7,052,414	9,804,977	14,204,250
Supplemental cash flow information:
Cash paid for interest	7,538,814	5,346,892	5,181,650
Cash paid for taxes			801,669
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties		28,140,092	207,843,194
Oil and natural gas property acquisition costs in accounts payable			2,042
Non-cash effect of Series A preferred unit redemption	14,983,784	25,847,891
Non-cash deemed distribution to Series A preferred units	9,431,794	$ 2,998,079	6,178,336
Distribution to Series A preferred unitholders in accounts payable			981,837
Right-of-use assets obtained in exchange for operating lease liabilities	19,636		$ 3,554,159
Recognition of tenant improvement asset	$ 447,917

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2021
ORGANIZATION AND BASIS OF PRESENTATION
ORGANIZATION AND BASIS OF PRESENTATION	Unless the context otherwise requi res, references to “Kimbell Royalty Partners, LP,” “the Partnership,” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner. References to “the Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership. NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION Organization Kimbell Royalty Partners, LP is a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGL”) from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest. Basis of Presentation The 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 reportable COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas The global spread of coronavirus (“COVID-19”) created significant volatility, uncertainty, and economic disruption during year ended 2020. On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing COVID-19 outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic reached more than 200 countries and resulted in widespread adverse impacts on the global economy, the Partnership’s oil, natural gas, and NGL operators and other parties with whom the Partnership has business relations, including a significant reduction in the global demand for oil and natural gas during the year ended 2020. The significant decline in demand accelerated following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries, raising concerns about global storage capacity. The resulting supply and demand imbalance led to a significantly weaker outlook for oil and gas producers in 2020. The Partnership modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention (the “CDC”), the WHO and other governmental and regulatory authorities. In mid-March 2020, the Partnership restricted access to its offices to only essential employees and directed the remainder of its employees to work from home to the extent possible. Beginning in mid-May 2020, the Partnership opened its offices to employees on a voluntary basis, with employees having the option to work from the office or from home. The Partnership will continue to give employees the option to work from the office or from home until the CDC recommends businesses and employers resume to pre-pandemic operations. These restrictions have had minimal impact on the Partnership’s operations to date and have allowed the Partnership to maintain the engagement and connectivity of its personnel, as well as minimize the number of employees in the office. The ultimate impacts of COVID-19 and the volatility in the oil and natural gas markets on the Partnership’s business, cash flows, liquidity, financial condition and results of operations remain dependent on a number of factors, including, among others, the ultimate severity of COVID-19, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other third parties, workforce availability, and the timing and extent of any return to normal economic and operating conditions.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2021
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, recoverability of costs of unevaluated properties, valuation of commodity and interest rate derivative financial instruments and the fair value of 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. 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. 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. Oil, Natural Gas and Receivables Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2021 and 2020, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs. Derivative Financial Instruments Commodity Derivatives 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 gain (loss) on commodity derivative instruments. Interest Rate Swaps The Partnership uses an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps are recognized as gains or losses in the current period and are presented on a net basis within other income in the consolidated statements of operations. 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 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. 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. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties. 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, 2021, 2020 or 2019. The Partnership assesses all unevaluated properties on periodic 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: economic and market conditions; 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. 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. 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 and to the full cost ceiling test. Due to the nature of the Partnership’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, 2021, 2020 or 2019. 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. Earnings Per Unit ​ Income Taxes As discussed further in Note 1—Organization and Basis of Presentation, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes, which became effective on September 24, 2018. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized. ​ 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, 2021, 2020 and 2019. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2021, 2020 and 2019, the Partnership did not recognize any interest or penalty expense related to uncertain tax positions. 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. During the years ended December 31, 2021, 2020 and 2019, the Partnership’s top ​ Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. See Note 4 ​ Non-controlling Interest ​ Revenue from Contracts with Customers The Partnership has 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 mineral or royalty interest. Revenue 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. 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 mineral or 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 NGL. 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 revenue 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 revenue contracts. Contract balances Under the Partnership’s revenue contracts, it would have the right to receive revenue from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s revenue contracts do not give rise to contract assets or liabilities under GAAP Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for one four months 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. Recently Adopted Pronouncements In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 Partnership adopted this update on January 1, 2021 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the year ended December 31, 2021.

ACQUISITIONS, JOINT VENTURES AN

ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY	12 Months Ended
	Dec. 31, 2021
ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY
ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY	NOTE 3—ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY Acquisitions 2021 Activity On March 10, 2021, the Partnership completed the acquisition of certain mineral and royalty assets held by Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP for a total purchase price of $0.5 million. The assets acquired were managed by Nail Bay Royalties and Duncan Management, LLC (“Duncan Management”). See Note 14—Related Party Transactions, for further discussion of the Partnership’s relation to each entity. On December 7, 2021, certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”) 2020 Activity On April 17, 2020, the Partnership completed the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”). The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, (ii) the issuance of 2,224,358 common units representing limited partner interests in the Partnership (“common units”) and (iii) the issuance of 2,497,134 newly issued common units of the Operating Company (“OpCo common units”) and an equal number of newly issued Class B common units representing limited partner interests of the Partnership (“Class B units”). At the time of the Springbok Acquisition, the acreage acquired had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other leading basins. 2019 Activity On March 25, 2019, the Partnership acquired all of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC that own oil and natural gas mineral and royalty interests (the “Phillips Acquisition”). The aggregate consideration for the Phillips Acquisition consisted of 9,400,000 OpCo common units and an equal number of Class B units 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 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. Joint Ventures On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture is 49.3% and its total capital commitment will not exceed its current investment of $5.1 million, as noted below. The Joint Venture is managed by Springbok Operating Company, LLC. While certain members of Springbok Operating Company, LLC are affiliated with the entities acquired as part of the Springbok Acquisition, none of the assets held by the Joint Venture were included in the Springbok Acquisition. The purpose of the Joint Venture is 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 currently utilizes the equity method of accounting for its investment in the Joint Venture. As of December 31, 2021, the Partnership has invested approximately $5.1 million under its capital commitment. Special Purpose Acquisition Company On July 29, 2021, TGR, our newly formed special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the United States Securities and Exchange Commission (“SEC”). TGR’s initial public offering was completed on February 8, 2022, with 23,000,000 units offered, including 3,000,000 units upon the underwriter’s exercise of its over-allotment option in full, at a price of $10.00 per unit. Each unit consists of one share of Class A common stock and one-half of one redeemable warrant. Each whole warrant may be exercised for one share of Class A common stock at a price of $11.50 per share. Certain members of our management and members of the Board of Directors are members of the sponsor of TGR. In connection with the closing of TGR’s initial public offering on February 8, 2022, the Partnership funded $14.1 million to TGR in exchange for 14,100,000 redeemable warrants. Each such warrant entitles the holder to purchase for $11.50, one share of TGR’s class A common stock, subject to adjustment. As of December 31, 2021, we incurred $0.9 million in deferred offering costs related to the proposed offering, which is included in other current assets in our consolidated balance sheets.

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2021
DERIVATIVES
DERIVATIVES	NOTE 4—DERIVATIVES Commodity 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, 2021, 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. As of December 31, 2021, these economic hedges constituted approximately 32% 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. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the current period and are presented on a net basis within revenue in the accompanying consolidated statements of operations. Interest Rate Swaps On January 27, 2021, the Partnership entered into an interest rate swap with Citibank, N.A., New York (“Citibank”) The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. Changes in the fair value consisted of the following: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Beginning fair value of derivative instruments ​ $ (6,280,863) ​ $ 804,501 ​ $ 4,227,946 Loss on derivative instruments ​ ​ (41,240,942) ​ ​ (2,450,541) ​ ​ (1,732,321) Net cash paid (received) on settlements of derivative instruments ​ ​ 20,897,159 ​ ​ (4,634,823) ​ ​ (1,691,124) Ending fair value of derivative instruments ​ $ (26,624,646) ​ $ (6,280,863) ​ $ 804,501 ​ The following table presents the fair value of the Partnership’s derivative contracts for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ December 31, Classification ​ Balance Sheet Location ​ 2021 ​ 2020 Assets: ​ ​ ​ ​ ​ ​ ​ ​ Current assets ​ Derivative assets ​ ​ 166,307 ​ ​ — Long-term assets ​ Derivative assets ​ $ 1,590,501 ​ $ — Liabilities: ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ Derivative liabilities ​ ​ (24,190,678) ​ ​ (3,113,178) Long-term liabilities ​ Derivative liabilities ​ ​ (4,190,776) ​ ​ (3,167,685) ​ ​ ​ ​ $ (26,624,646) ​ $ (6,280,863) ​ At December 31, 2021, 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 January 2022 - December 2022 ​ 500,552 ​ $ 41.86 ​ $ 35.65 ​ $ 46.00 January 2023 - December 2023 ​ 303,411 ​ $ 59.35 ​ $ 53.38 ​ $ 63.00 Natural Gas Price Swaps ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Notional ​ Weighted Average ​ Range (per MMBtu) ​ ​ Volumes (MMBtu) ​ Fixed Price (per MMBtu) ​ Low ​ High January 2022 - December 2022 ​ 6,357,449 ​ $ 2.46 ​ $ 2.23 ​ $ 2.70 January 2023 - December 2023 ​ 4,245,899 ​ $ 2.90 ​ $ 2.52 ​ $ 3.28 ​

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 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, 2021 and 2020. Both the Partnership’s commodity derivative instruments and interest rate swap 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, 2021 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest rate swap contracts ​ $ — ​ $ 1,756,808 ​ $ — ​ $ — ​ $ 1,756,808 Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ (28,381,454) ​ $ — ​ $ — ​ $ (28,381,454) December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ (6,280,863) ​ $ — ​ $ — ​ $ (6,280,863) ​

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	12 Months Ended
	Dec. 31, 2021
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, ​ ​ 2021 ​ 2020 Oil and natural gas properties ​ ​ ​ ​ ​ ​ Proved properties ​ $ 1,051,111,311 ​ $ 923,413,606 Unevaluated properties ​ ​ 153,284,173 ​ ​ 225,681,626 Less: accumulated depreciation, depletion and impairment ​ ​ (663,603,142) ​ ​ (628,102,279) Total oil and natural gas properties ​ $ 540,792,342 ​ $ 520,992,953 ​ After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined in 2020 that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated proved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties in the first quarter of 2020. The Partnership did not book PUD reserves in its total estimated proved reserves as of December 31, 2021 or 2020 and it does not intend to book PUD reserves going forward. The Partnership did not record an impairment on its oil and natural gas properties for the year ended December 31, 2021 due to the increase in the twelve-month average oil and gas index prices, calculated as the unweighted average for first-day-of-the-month price for each month. As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $251.6 million during the year ended December 31, 2020, including the $48.6 million in unevaluated properties transferred to the full cost pool. The impairment can primarily be attributed to the decline in the 12-month average price of oil and natural gas during the year ended December 31, 2020. 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.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2021
LEASES
LEASES	NOTE 7—LEASES Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s right-of-use (“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 sheets. Short-term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of December 31, 2021 is 7.35 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 secured revolving credit facility. 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, 2021. 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 statements of operations for the years ended December 31, 2021, 2020 and 2019. The total operating lease expense recorded for the years ended December 31, 2021, 2020 and 2019 was $0.4 million, $0.5 million and $0.3 million, respectively. Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces 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. Future minimum lease commitments as of December 31, 2021 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ 2022 ​ 2023 ​ 2024 ​ 2025 ​ 2026 ​ Thereafter Operating leases ​ $ 3,686,505 ​ $ 486,045 ​ $ 487,787 ​ $ 488,725 ​ $ 497,033 ​ $ 507,648 ​ $ 1,219,267 Less: Imputed Interest ​ (823,006) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ $ 2,863,499 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2021
LONG-TERM DEBT.
LONG-TERM DEBT	NOTE 8—LONG-TERM DEBT 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, the Partnership entered into an amendment (the “First Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement (the 2017 Credit Agreement as amended by the First Credit Agreement Amendment, the “2018 Amended Credit Agreement”). On December 8, 2020, the Partnership entered into Amendment No. 2 (the “Second Credit Agreement Amendment”) to the 2018 Amended Credit Agreement (the 2018 Amended Credit Agreement as amended by the Second Credit Agreement Amendment, the “Amended Credit Agreement”). The Second Credit Agreement Amendment amends the 2018 Amended Credit Agreement to, among other things, (i) increase commitments under the Amended Credit Agreement’s senior secured revolving credit facility from $225.0 million to $265.0 million, the availability of which will equal the lesser of the aggregate maximum elected commitments of the lenders up to $500.0 million, subject to the satisfaction of certain conditions and the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders, and the borrowing base, (ii) extend the maturity date under the 2018 Amended Credit Agreement from February 8, 2022 to June 7, 2024, (iii) reflect the change in administrative agent from Frost to Citibank under the Amended Credit Agreement, (iv) increase the applicable margin under the 2018 Amended Credit Agreement, which varies based upon the level of borrowing base usage, by 1.00% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 2.00% to 3.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 3.00% to 4.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement), (v) a LIBOR (as defined in the Amended Credit Agreement) floor of 0.25% , (vi) modify the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) financial covenant to permit the numerator of the Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) to be calculated as Total Debt (as defined in the Amended Credit Agreement) minus up to $25 million in unrestricted cash held by the Partnership and its restricted subsidiaries and to decreases the maximum permitted Debt to EBITDAX Ratio (as defined in the Amended Credit Agreement) from 4.0 to 1.0 to 3.5 to 1.0, and (vii) modify the conditions permitting restricted distributions to holders of Kimbell Common Units (as defined in the Amended Credit Agreement) including, among other things, a limitation on such distributions to not be in excess of the Partnership’s Projected Cash Available For Distribution (as defined in the Amended Credit Agreement). We are obligated to pay a quarterly commitment fee of 0.50% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing based. In connection with our entry into the Second Credit Agreement Amendment, the borrowing base was set at $265.0 million. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year, beginning May 1, 2021, 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 November 1, 2021 redetermination under the secured revolving credit facility, the borrowing base was increased to $275.0 million. 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 and OpCo 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 Amended Credit Agreement 3.5 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. In connection with the Second Credit Agreement Amendment, the Partnership recorded a loss on extinguishment of debt of $0.5 million for the year ended December 31, 2020, as a result of writing off all unamortized loan origination costs associated with the lenders to the 2017 Credit Agreement and the 2018 Amended Credit Agreement that did not participate in the Second Credit Agreement Amendment. During the year ended December 31, 2021, the Partnership borrowed an additional $136.6 million under the secured revolving credit facility and repaid approximately $91.0 million of the outstanding borrowings. As of December 31, 2021, the Partnership’s outstanding balance was $217.1 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2021. As of December 31, 2021, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 3.75% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.75%. For the year ended December 31, 2021, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.86%.

PREFERRED UNITS

PREFERRED UNITS	12 Months Ended
	Dec. 31, 2021
PREFERRED UNITS
PREFERRED UNITS	NOTE 9—PREFERRED UNITS In July 2018, the Partnership completed the private placement of 110,000 newly issued Series A Cumulative Convertible Preferred Units (“Series A preferred units”) to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $110.0 million. Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the third anniversary of the original issuance date, and board appointment rights beginning the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A preferred units. In May 2021, the Series A Purchasers and the Partnership agreed to waive the board observer rights, that were set to begin in July 2021, until January 2022. 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 For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of 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. 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. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than 50% of the carrying value of the Series A preferred units as of the redemption date and 50% of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $5.7 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2020. On July 7, 2021, the Partnership completed the redemption of 30,000 Series A preferred units, representing 55% of the then-outstanding Series A preferred units, with 25,000 Series A preferred units still outstanding. The Series A preferred units were redeemed at a price of $1,202.51 per Series A preferred unit for an aggregate redemption price of $36.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date and the redeemed portion of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $3.8 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2021. On December 7, 2021, the Partnership completed the redemption of the remaining 25,000 Series A preferred units. The Series A preferred units were redeemed at a price of $1,240.25 per Series A preferred unit for an aggregate redemption price of $31.0 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date and the remaining intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $3.6 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2021. The following table summarizes the changes in the number of the Series A preferred units: ​ ​ ​ ​ ​ ​ Series A ​ ​ Preferred Units Balance at December 31, 2020 ​ 55,000 Redemption of Series A preferred units ​ (55,000) Balance at December 31, 2021 ​ - ​

UNITHOLDERS' EQUITY AND PARTNER

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS	12 Months Ended
	Dec. 31, 2021
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS	NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS The Partnership has issued units representing limited partner interests. At December 31, 2021, the Partnership had a total of 47,162,773 common units issued and outstanding In January 2020, the Partnership completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 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 secured revolving credit facility. 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. In November 2021, the Partnership completed an underwritten public offering of 4,312,500 common units for net proceeds of approximately $57.7 million (the “2021 Equity Offering”). The Partnership used the net proceeds from the 2021 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $56.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. The following table summarizes the changes in the number of the Partnership’s common units: ​ ​ ​ ​ ​ ​ Common Units Balance at December 31, 2020 ​ 38,918,689 Common units issued for equity offering ​ 4,312,500 Conversion of Class B units ​ 3,168,202 Common units issued under the LTIP (1) ​ 936,567 Restricted units repurchased for tax withholding ​ (173,185) Balance at December 31, 2021 ​ 47,162,773 (1) Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on February 25, 2021. The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the periods presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amount per ​ Date ​ Unitholder ​ Payment ​ ​ Common Unit ​ Declared ​ Record Date ​ Date Q1 2021 ​ $ 0.27 ​ April 23, 2021 ​ May 3, 2021 ​ May 10, 2021 Q2 2021 ​ $ 0.31 ​ July 23, 2021 ​ August 2, 2021 ​ August 9, 2021 Q3 2021 ​ $ 0.37 ​ October 22, 2021 ​ November 1, 2021 ​ November 8, 2021 Q4 2021 ​ $ 0.37 ​ January 21, 2022 ​ January 31, 2022 ​ February 7, 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Q1 2020 ​ $ 0.17 ​ April 24, 2020 ​ May 4, 2020 ​ May 11, 2020 Q2 2020 ​ $ 0.13 ​ July 24, 2020 ​ August 3, 2020 ​ August 10, 2020 Q3 2020 ​ $ 0.19 ​ October 23, 2020 ​ November 2, 2020 ​ November 9, 2020 Q4 2020 ​ $ 0.19 ​ January 22, 2021 ​ February 1, 2021 ​ February 8, 2021 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ The following table summarizes the changes in the number of the Partnership’s Class B units: ​ ​ ​ ​ ​ ​ Class B Units Balance at December 31, 2020 ​ 20,779,781 Conversion of Class B units ​ (3,168,202) Balance at December 31, 2021 ​ 17,611,579 ​ 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 but prior to distributions on the common units and OpCo common units. Holders of the Class B units are entitled to one vote per share on all matters to be voted upon by the shareholders. Holders of the common units and the Class B units generally vote together as a single class on all matters presented to the Kimbell Royalty Partners, LP unitholders for their vote or approval. Holders of Class B units do not have any right to receive dividends or distributions upon a liquidation or winding up of Kimbell Royalty Partners, LP. The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

EARNINGS (LOSS) PER COMMON UNIT

EARNINGS (LOSS) PER COMMON UNIT	12 Months Ended
	Dec. 31, 2021
EARNINGS (LOSS) PER COMMON UNIT
EARNINGS (LOSS) PER COMMON UNIT	NOTE 11—EARNINGS (LOSS) PER COMMON UNIT Basic earnings (loss) per common unit 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 Partnership’s LTIP for its employees, directors and consultants and potential conversion of Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Class B units (and corresponding units of Kimbell Royalty Partners, LP), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding restricted units granted under the Partnership’s LTIP. The Partnership does not use the two-class method because the Class B units and the unvested restricted units granted under the Partnership’s LTIP are nonparticipating securities. The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted earnings (loss) per common unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Net income (loss) attributable to common units ​ $ 22,615,021 ​ $ (167,350,893) ​ $ (83,032,282) Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interests ​ ​ 8,496,104 ​ ​ — ​ ​ — Diluted net income (loss) attributable to common units ​ ​ 31,111,125 ​ ​ (167,350,893) ​ ​ (83,032,282) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of common units outstanding: ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ ​ 40,400,907 ​ ​ 34,530,398 ​ ​ 21,192,714 Effect of dilutive securities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Series A preferred units ​ ​ — ​ ​ — ​ ​ — Class B units ​ ​ 18,839,607 ​ ​ — ​ ​ — Restricted units ​ ​ 1,717,310 ​ ​ — ​ ​ — Diluted ​ ​ 60,957,824 ​ ​ 34,530,398 ​ ​ 21,192,714 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) attributable to common units ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ $ 0.56 ​ $ (4.85) ​ $ (3.92) Diluted ​ $ 0.51 ​ $ (4.85) ​ $ (3.92) ​ The calculation of diluted net income per share for the year ended December 31, 2021 includes the conversion of all Class B units to common units calculated using the “if-converted” method and 1,717,310 units of unvested restricted units calculated using the treasury stock method. The calculation of diluted net loss per share for the years ended December 31, 2020 and 2019 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 1,276,546 and 739,479 units of unvested restricted units, respectively, because their inclusion in the calculation would be anti-dilutive.

UNIT-BASED COMPENSATION

UNIT-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2021
UNIT-BASED COMPENSATION
UNIT-BASED COMPENSATION	NOTE 12—UNIT-BASED COMPENSATION The Partnership’s LTIP authorizes grants of up to 4,541,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued one three 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Weighted ​ ​ ​ ​ Average ​ Average ​ ​ ​ ​ Grant-Date ​ Remaining ​ ​ ​ ​ Fair Value ​ Contractual ​ ​ Units ​ per Unit ​ Term Unvested at December 31, 2020 ​ 1,276,546 ​ $ 13.604 1.788 years Awarded ​ 936,567 ​ ​ 10.350 ​ — Vested ​ (652,214) ​ ​ 14.905 ​ — Unvested at December 31, 2021 ​ 1,560,899 ​ $ 11.108 1.775 years ​

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2021
INCOME TAXES
INCOME TAXES	NOTE 13—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. 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, 2021, 2020 and 2019. The Partnership has filed all tax returns to date that are currently due. On March 27, 2020, the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act “) was enacted. The CARES Act is an economic stimulus package designed to aid in offsetting the economic damage caused by the ongoing COVID-19 pandemic and includes various changes to U.S. income tax regulations. The CARES Act permits the carryback of certain net operating losses that under previous law were only available to be carried forward. ​ The Partnership’s effective income tax rate was 0.17% for the year ended December 31, 2021. The Partnership earned book income for the current year and is recording a current income tax expense of $0.1 million primarily related to unsheltered taxable income. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Current ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ $ 69,067 ​ $ (812,913) ​ $ 812,913 State ​ ​ 5,033 ​ ​ (72,280) ​ ​ 86,512 Total Current ​ ​ 74,100 ​ ​ (885,193) ​ ​ 899,425 Deferred ​ ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ ​ — ​ ​ — ​ ​ — State ​ ​ — ​ ​ — ​ ​ — Total Deferred ​ ​ — ​ ​ — ​ ​ — Provision for (benefit from) income taxes ​ $ 74,100 ​ $ (885,193) ​ $ 899,425 ​ 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: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Net income (loss) before taxes ​ $ 42,511,974 ​ ​ $ (256,975,963) ​ ​ $ (157,308,520) ​ Statutory rate ​ ​ 21 % ​ ​ 21 % ​ ​ 21 % Income tax provision (benefit) computed at statutory rate ​ ​ 8,927,515 ​ ​ ​ (53,964,952) ​ ​ ​ (33,034,789) ​ Reconciling items: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ State income taxes ​ ​ 5,033 ​ ​ ​ (72,280) ​ ​ ​ 72,280 ​ Non-controlling interest ​ ​ (1,788,347) ​ ​ ​ 20,294,890 ​ ​ ​ 18,721,170 ​ (Income) loss at OpCo ​ ​ (7,139,168) ​ ​ ​ 33,670,062 ​ ​ ​ 15,130,685 ​ Change in valuation allowance - federal ​ ​ (363,132) ​ ​ ​ (749,866) ​ ​ ​ 80,520 ​ Change in valuation allowance - state ​ ​ (40,626) ​ ​ ​ 168,393 ​ ​ ​ (70,441) ​ Other, net ​ ​ 472,825 ​ ​ ​ (231,440) ​ ​ ​ — ​ Provision for (benefit from) income taxes ​ $ 74,100 ​ ​ $ (885,193) ​ ​ $ 899,425 ​ ​ 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. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Deferred tax asset ​ ​ ​ ​ ​ ​ Outside basis in OpCo ​ $ 6,641,452 ​ $ 17,624,909 ​ $ 20,050,732 Federal tax loss carryforwards ​ ​ 12,296,282 ​ ​ 1,675,957 ​ ​ — State tax loss carryforwards ​ ​ 1,789,961 ​ ​ 238,559 ​ ​ — Deferred tax asset ​ ​ 20,727,695 ​ ​ 19,539,425 ​ ​ 20,050,732 Valuation allowance ​ ​ (20,727,695) ​ ​ (19,539,425) ​ ​ (20,050,732) Net deferred tax asset ​ $ — ​ $ — ​ $ — Deferred tax liability ​ ​ ​ ​ ​ ​ ​ ​ ​ Derivative instruments and other ​ ​ — ​ ​ — ​ ​ — Net deferred tax liability ​ $ — ​ $ — ​ $ — Reflected in the accompanying balance sheets as: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax asset ​ $ — ​ $ — ​ $ — Net deferred tax liability ​ $ — ​ $ — ​ $ — ​ The tax years ended December 31, 2018 through 2021 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 and its federal and state loss carryforward will not be realized. In recognition of this risk, the Partnership has provided a valuation allowance of $20.7 million on the deferred tax assets. As of December 31, 2021, the Partnership has not

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2021
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	NOTE 14—RELATED PARTY TRANSACTIONS The Partnership has entered into a management services agreement with Kimbell Operating, which has entered into separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), 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 on common units to the Partnership’s unitholders. During the year ended December 31, 2021, no monthly services fee was paid to BJF Royalties. During the year ended December 31, 2021, the Partnership made payments to K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $120,000, $301,314 and $548,480, respectively. Certain consultants who provide services under the management services agreements are also granted restricted units under the Partnership’s LTIP. During the year ended December 31, 2021, the Partnership acquired certain assets managed by Nail Bay Royalties and Duncan Management. See Note 3 ​ John Wynne, the son of Mitch S. Wynne, acts as the Partnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne derived a commission of approximately $22,160, $20,160 and $18,900 for the years ended December 31, 2021, 2020 and 2019, respectively, for the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $555,640, $440,160 and $350,000 for the years ended December 31, 2021, 2020 and 2019, respectively. Special Purpose Acquisition Company On February 8, 2022, TGR’s initial public offering was completed with 23,000,000 units offered, including 3,000,000 units upon the underwriter’s exercise of its over-allotment option in full, at a price of $10.00 per unit. During the year ended December 31, 2021, the Partnership paid $930,824 in formation and offering costs on behalf of TGR. This amount is included in other current assets on the consolidated balance sheets as of December 31, 2021. See Note 3—Acquisitions, Joint Ventures and Special Purpose Acquisition Company for further discussion.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2021
COMMITMENTS AND CONTINGENCIES.
COMMITMENTS AND CONTINGENCIES	NOTE 15—COMMITMENTS AND CONTINGENCIES Leases The Partnership leases certain office space under non-cancelable operating leases with fixed payment terms and will terminate in June 2029. The Partnership recognizes operating lease expense over the lease term and is included in general and administrative expense in the accompanying consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019. The total operating lease expense recorded for the years ended December 31, 2021, 2020 and 2019 was approximately $0.4 million, $0.5 million and $0.3 million, respectively. Operating lease liabilities, excluding the current portion, as of the year ended December 31, 2021 and 2020, respectively, was $2.6 million and $2.8 million. Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2021: ​ ​ ​ ​ ​ Years Ending December 31, ​ 2022 ​ $ 486,045 2023 ​ 487,787 2024 ​ 488,725 2025 ​ 497,033 2026 ​ ​ 507,648 Thereafter ​ ​ 1,219,267 Total ​ $ 3,686,505 ​ Litigation During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. 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 as of December 31, 2021.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2021
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 16—SUBSEQUENT EVENTS The Partnership has evaluated events that occurred subsequent to December 31, 2021 in the preparation of its consolidated financial statements. Debt On January 14, 2022 and January 27, 2022, the Partnership drew down approximately $12.9 million and $1.2 million, respectively, on the senior secured revolving credit facility to fund the closing of TGR’s initial public offering on February 8, 2022. On January 28, 2022, the Partnership drew down $5.0 million on the senior secured revolving credit facility to fund certain operational expenses. Distributions On February 7, 2022, 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 $17,610 for the quarter ended December 31, 2021. On January 21, 2022, the Board of Directors declared a quarterly cash distribution of $0.37 per common unit for the quarter ended December 31, 2021. The distribution was paid on February 7, 2022 to common unitholders and OpCo common unitholders of record as of the close of business on January 31, 2022. On February 24, 2022, the Conflicts and Compensation Committee of the Board of Directors approved short-term incentive cash bonuses for executive officers of $2.2 million and the issuance of 963,835 restricted units to its employees, directors and consultants. Special Purpose Acquisition Company On February 8, 2022, TGR’s initial public offering was completed with 23,000,000 units offered, including 3,000,000 units upon the underwriter’s exercise of its over-allotment option in full, at a price of $10.00 per unit. See Note 3—Acquisitions, Joint Ventures and Special Purpose Acquisition Company for further discussion. ​

SUPPLEMENTAL OIL AND GAS RESERV

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2021
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, ​ 2021 ​ 2020 Oil, natural gas and NGL interests ​ ​ ​ ​ ​ ​ Proved properties ​ $ 1,051,111,311 ​ $ 923,413,606 Unevaluated properties ​ ​ 153,284,173 ​ ​ 225,681,626 Total oil, natural gas and NGL interests ​ 1,204,395,484 ​ 1,149,095,232 Accumulated depreciation, depletion, accretion and impairment ​ (663,603,142) ​ (628,102,279) Net oil, natural gas and NGL interests capitalized ​ $ 540,792,342 ​ $ 520,992,953 ​ Costs incurred in oil and natural gas activities Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Acquisition costs ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved properties ​ $ 55,300,252 ​ $ 41,476,733 ​ $ 104,199,579 Unevaluated properties ​ ​ — ​ ​ 74,263,481 ​ ​ 110,050,000 Total ​ 55,300,252 ​ 115,740,214 ​ 214,249,579 Development costs ​ ​ ​ Proved properties ​ — ​ — ​ — Total ​ — ​ — ​ — Total costs incurred on oil, natural gas and NGL activities ​ $ 55,300,252 ​ $ 115,740,214 ​ $ 214,249,579 ​ 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 oil, natural gas and NGL operations. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Oil, natural gas and NGL revenues ​ $ 175,088,021 ​ $ 92,586,685 ​ $ 107,480,446 Lease bonus and other income ​ ​ 3,319,104 ​ ​ 345,771 ​ ​ 2,477,145 Production and ad valorem taxes ​ (10,480,481) ​ (6,389,231) ​ (7,719,949) Depreciation and depletion expense ​ (36,797,881) ​ (47,988,796) ​ (52,118,367) Impairment of oil and natural gas properties ​ — ​ (251,558,557) ​ (169,150,255) Marketing and other deductions ​ (12,048,643) ​ (9,376,375) ​ (8,145,397) Results of operations from oil, natural gas and NGLs ​ $ 119,080,120 ​ $ (222,380,503) ​ $ (127,176,377) ​ 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, 2021, 2020 and 2019. 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 price 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, 2019 ​ 10,795 ​ 127,261 ​ 5,646 ​ 37,651 Revisions of previous estimates (1) ​ 849 ​ 25,398 ​ 684 ​ 5,766 Purchase of minerals in place (2) ​ 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 Revisions of previous estimates (1) ​ 18 ​ (2,256) ​ (2) ​ (359) Purchase of minerals in place (3) ​ 1,367 ​ 15,637 ​ 313 ​ 4,286 Production ​ (1,409) ​ (17,890) ​ (681) ​ (5,072) Net proved reserves at December 31, 2020 ​ 12,294 ​ 144,233 ​ 6,085 ​ 42,418 Revisions of previous estimates (1) ​ 251 ​ 24,079 ​ 780 ​ 5,044 Purchase of minerals in place (4) ​ 1,310 ​ 8,537 ​ 519 ​ 3,252 Production ​ (1,344) ​ (19,085) ​ (715) ​ (5,240) Net proved reserves at December 31, 2021 ​ 12,511 ​ 157,764 ​ 6,669 ​ 45,474 ​ ​ ​ ​ ​ ​ ​ ​ ​ Net proved developed reserves ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ 11,303 ​ 141,181 ​ 6,079 ​ 40,912 December 31, 2020 ​ 12,294 ​ 144,233 ​ 6,085 ​ 42,418 December 31, 2021 ​ 12,511 ​ 157,764 ​ 6,669 ​ 45,474 ​ ​ ​ ​ ​ ​ ​ ​ ​ Net proved undeveloped reserves ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ 1,015 ​ 7,561 ​ 376 ​ 2,651 December 31, 2020 ​ — ​ — ​ — ​ — December 31, 2021 ​ — ​ — ​ — ​ — (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 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. (3) Includes the acquisition of mineral and royalty interests for a total of $41.5 million. The acquisition consists of mineral and royalty interests primarily in the Delaware Basin, DJ Basin, Haynesville, STACK and Eagle Ford. (4) Includes the acquisition of mineral and royalty interests for a total of $55.3 million, primarily consisting of mineral and royalty interests in the Permian Basin, Mid-Continent, Haynesville and other leading U.S. basins. ​ 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, ​ 2021 ​ 2020 ​ 2019 Future cash inflows ​ $ 1,335,917 ​ $ 705,356 ​ $ 1,025,430 Future production costs ​ ​ (100,947) ​ ​ (55,897) ​ ​ (78,061) Future state margin taxes ​ ​ (42,965) ​ ​ (22,688) ​ ​ (32,377) Future income tax expense ​ ​ — ​ ​ — ​ ​ (33,235) Future net cash flows ​ ​ 1,192,005 ​ ​ 626,771 ​ ​ 881,757 Less 10% annual discount to reflect timing of cash flows ​ ​ (665,390) ​ ​ (341,775) ​ ​ (481,786) Standard measure of discounted future net cash flows ​ $ 526,615 ​ $ 284,996 ​ $ 399,971 ​ 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 2021, 2020 and 2019 were $66.56, $39.57 and $55.69 per barrel for crude oil and $3.60, $1.99 and $2.58 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, ​ ​ 2021 ​ 2020 ​ 2019 Standardized measure - beginning of year ​ $ 284,996 ​ $ 399,971 ​ $ 398,367 Sales, net of production costs ​ ​ (152,751) ​ ​ (76,821) ​ ​ (93,942) Net changes of prices and production costs related to future production ​ ​ 225,868 ​ ​ (127,838) ​ ​ (72,875) Revisions of previous quantity estimates, net of related costs ​ ​ 60,517 ​ ​ (2,501) ​ ​ 56,666 Net changes in state margin taxes ​ ​ (8,665) ​ ​ 4,314 ​ ​ 191 Net changes in income taxes ​ ​ — ​ ​ 13,480 ​ ​ 3,752 Accretion of discount ​ ​ 25,743 ​ ​ 38,927 ​ ​ 42,808 Purchases of reserves in place ​ ​ 40,545 ​ ​ 46,007 ​ ​ 59,953 Timing differences and other ​ ​ 50,362 ​ ​ (10,543) ​ ​ 5,051 Standardized measure - end of year ​ $ 526,615 ​ $ 284,996 ​ $ 399,971 ​

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2021
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 reportable
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, recoverability of costs of unevaluated properties, valuation of commodity and interest rate derivative financial instruments and the fair value of 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.
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. 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.
Oil, Natural Gas and Receivables	Oil, Natural Gas and Receivables Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2021 and 2020, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs.
Derivative Financial Instruments	Derivative Financial Instruments Commodity Derivatives 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 gain (loss) on commodity derivative instruments. Interest Rate Swaps The Partnership uses an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps are recognized as gains or losses in the current period and are presented on a net basis within other income in the consolidated statements of operations.
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
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. 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. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties. 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, 2021, 2020 or 2019. The Partnership assesses all unevaluated properties on periodic 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: economic and market conditions; 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. 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. 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 and to the full cost ceiling test. Due to the nature of the Partnership’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, 2021, 2020 or 2019.
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.
Earnings Per Unit	Earnings Per Unit ​
Income Taxes	Income Taxes As discussed further in Note 1—Organization and Basis of Presentation, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes, which became effective on September 24, 2018. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized. ​ 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, 2021, 2020 and 2019. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2021, 2020 and 2019, the Partnership did not recognize any interest or penalty expense related to uncertain tax positions.
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. During the years ended December 31, 2021, 2020 and 2019, the Partnership’s top ​ Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. See Note 4 ​
Non-controlling Interest	Non-controlling Interest ​
Revenue from Contracts with Customers	Revenue from Contracts with Customers The Partnership has 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 mineral or royalty interest. Revenue 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. 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 mineral or 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 NGL. 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 revenue 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 revenue contracts. Contract balances Under the Partnership’s revenue contracts, it would have the right to receive revenue from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s revenue contracts do not give rise to contract assets or liabilities under GAAP Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for one four months
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.
Recently Adopted Pronouncements	Recently Adopted Pronouncements In December 2019, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 Partnership adopted this update on January 1, 2021 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the year ended December 31, 2021.

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2021
DERIVATIVES
Schedule of changes in fair value of derivative instruments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Beginning fair value of derivative instruments ​ $ (6,280,863) ​ $ 804,501 ​ $ 4,227,946 Loss on derivative instruments ​ ​ (41,240,942) ​ ​ (2,450,541) ​ ​ (1,732,321) Net cash paid (received) on settlements of derivative instruments ​ ​ 20,897,159 ​ ​ (4,634,823) ​ ​ (1,691,124) Ending fair value of derivative instruments ​ $ (26,624,646) ​ $ (6,280,863) ​ $ 804,501
Schedule of derivative contracts	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ December 31, Classification ​ Balance Sheet Location ​ 2021 ​ 2020 Assets: ​ ​ ​ ​ ​ ​ ​ ​ Current assets ​ Derivative assets ​ ​ 166,307 ​ ​ — Long-term assets ​ Derivative assets ​ $ 1,590,501 ​ $ — Liabilities: ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ Derivative liabilities ​ ​ (24,190,678) ​ ​ (3,113,178) Long-term liabilities ​ Derivative liabilities ​ ​ (4,190,776) ​ ​ (3,167,685) ​ ​ ​ ​ $ (26,624,646) ​ $ (6,280,863)
Schedule of commodity derivative contracts	Oil Price Swaps ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Notional ​ Weighted Average ​ Range (per Bbl) ​ ​ Volumes (Bbl) ​ Fixed Price (per Bbl) ​ Low ​ High January 2022 - December 2022 ​ 500,552 ​ $ 41.86 ​ $ 35.65 ​ $ 46.00 January 2023 - December 2023 ​ 303,411 ​ $ 59.35 ​ $ 53.38 ​ $ 63.00 Natural Gas Price Swaps ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Notional ​ Weighted Average ​ Range (per MMBtu) ​ ​ Volumes (MMBtu) ​ Fixed Price (per MMBtu) ​ Low ​ High January 2022 - December 2022 ​ 6,357,449 ​ $ 2.46 ​ $ 2.23 ​ $ 2.70 January 2023 - December 2023 ​ 4,245,899 ​ $ 2.90 ​ $ 2.52 ​ $ 3.28

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2021
FAIR VALUE MEASUREMENTS
Schedule of assets and liabilities measured at fair value on a recurring basis	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements Using ​ ​ ​ ​ ​ ​ ​ ​ Level 1 ​ Level 2 ​ Level 3 ​ Effect of Counterparty Netting ​ Total December 31, 2021 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest rate swap contracts ​ $ — ​ $ 1,756,808 ​ $ — ​ $ — ​ $ 1,756,808 Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ (28,381,454) ​ $ — ​ $ — ​ $ (28,381,454) December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ (6,280,863) ​ $ — ​ $ — ​ $ (6,280,863)

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2021
OIL AND NATURAL GAS PROPERTIES
Schedule of oil and natural gas properties	​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ December 31, ​ ​ 2021 ​ 2020 Oil and natural gas properties ​ ​ ​ ​ ​ ​ Proved properties ​ $ 1,051,111,311 ​ $ 923,413,606 Unevaluated properties ​ ​ 153,284,173 ​ ​ 225,681,626 Less: accumulated depreciation, depletion and impairment ​ ​ (663,603,142) ​ ​ (628,102,279) Total oil and natural gas properties ​ $ 540,792,342 ​ $ 520,992,953

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2021
LEASES
Schedule of future minimum lease commitments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ 2022 ​ 2023 ​ 2024 ​ 2025 ​ 2026 ​ Thereafter Operating leases ​ $ 3,686,505 ​ $ 486,045 ​ $ 487,787 ​ $ 488,725 ​ $ 497,033 ​ $ 507,648 ​ $ 1,219,267 Less: Imputed Interest ​ (823,006) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ $ 2,863,499 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

PREFERRED UNITS (Tables)

PREFERRED UNITS (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2020 ​ 55,000 Redemption of Series A preferred units ​ (55,000) Balance at December 31, 2021 ​ -

UNITHOLDERS' EQUITY AND PARTN_2

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Tables)	12 Months Ended
	Dec. 31, 2021
Common units
Schedule of distributions approved by the Board of Directors	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amount per ​ Date ​ Unitholder ​ Payment ​ ​ Common Unit ​ Declared ​ Record Date ​ Date Q1 2021 ​ $ 0.27 ​ April 23, 2021 ​ May 3, 2021 ​ May 10, 2021 Q2 2021 ​ $ 0.31 ​ July 23, 2021 ​ August 2, 2021 ​ August 9, 2021 Q3 2021 ​ $ 0.37 ​ October 22, 2021 ​ November 1, 2021 ​ November 8, 2021 Q4 2021 ​ $ 0.37 ​ January 21, 2022 ​ January 31, 2022 ​ February 7, 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Q1 2020 ​ $ 0.17 ​ April 24, 2020 ​ May 4, 2020 ​ May 11, 2020 Q2 2020 ​ $ 0.13 ​ July 24, 2020 ​ August 3, 2020 ​ August 10, 2020 Q3 2020 ​ $ 0.19 ​ October 23, 2020 ​ November 2, 2020 ​ November 9, 2020 Q4 2020 ​ $ 0.19 ​ January 22, 2021 ​ February 1, 2021 ​ February 8, 2021 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​
Common Units
Common units
Schedule of changes in Partnership's units	​ ​ ​ ​ ​ ​ Common Units Balance at December 31, 2020 ​ 38,918,689 Common units issued for equity offering ​ 4,312,500 Conversion of Class B units ​ 3,168,202 Common units issued under the LTIP (1) ​ 936,567 Restricted units repurchased for tax withholding ​ (173,185) Balance at December 31, 2021 ​ 47,162,773 (1) Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on February 25, 2021.
Class B
Common units
Schedule of changes in Partnership's units	​ ​ ​ ​ ​ ​ Class B Units Balance at December 31, 2020 ​ 20,779,781 Conversion of Class B units ​ (3,168,202) Balance at December 31, 2021 ​ 17,611,579

EARNINGS (LOSS) PER COMMON UN_2

EARNINGS (LOSS) PER COMMON UNIT (Tables)	12 Months Ended
	Dec. 31, 2021
EARNINGS (LOSS) PER COMMON UNIT
Schedule of earnings (loss) per unit	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Net income (loss) attributable to common units ​ $ 22,615,021 ​ $ (167,350,893) ​ $ (83,032,282) Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interests ​ ​ 8,496,104 ​ ​ — ​ ​ — Diluted net income (loss) attributable to common units ​ ​ 31,111,125 ​ ​ (167,350,893) ​ ​ (83,032,282) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of common units outstanding: ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ ​ 40,400,907 ​ ​ 34,530,398 ​ ​ 21,192,714 Effect of dilutive securities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Series A preferred units ​ ​ — ​ ​ — ​ ​ — Class B units ​ ​ 18,839,607 ​ ​ — ​ ​ — Restricted units ​ ​ 1,717,310 ​ ​ — ​ ​ — Diluted ​ ​ 60,957,824 ​ ​ 34,530,398 ​ ​ 21,192,714 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) attributable to common units ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ $ 0.56 ​ $ (4.85) ​ $ (3.92) Diluted ​ $ 0.51 ​ $ (4.85) ​ $ (3.92)

UNIT-BASED COMPENSATION (Tables

UNIT-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2020 ​ 1,276,546 ​ $ 13.604 1.788 years Awarded ​ 936,567 ​ ​ 10.350 ​ — Vested ​ (652,214) ​ ​ 14.905 ​ — Unvested at December 31, 2021 ​ 1,560,899 ​ $ 11.108 1.775 years

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2021
INCOME TAXES
Schedule of income tax expense	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Current ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ $ 69,067 ​ $ (812,913) ​ $ 812,913 State ​ ​ 5,033 ​ ​ (72,280) ​ ​ 86,512 Total Current ​ ​ 74,100 ​ ​ (885,193) ​ ​ 899,425 Deferred ​ ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ ​ — ​ ​ — ​ ​ — State ​ ​ — ​ ​ — ​ ​ — Total Deferred ​ ​ — ​ ​ — ​ ​ — Provision for (benefit from) income taxes ​ $ 74,100 ​ $ (885,193) ​ $ 899,425
Schedule of effective income expense	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Net income (loss) before taxes ​ $ 42,511,974 ​ ​ $ (256,975,963) ​ ​ $ (157,308,520) ​ Statutory rate ​ ​ 21 % ​ ​ 21 % ​ ​ 21 % Income tax provision (benefit) computed at statutory rate ​ ​ 8,927,515 ​ ​ ​ (53,964,952) ​ ​ ​ (33,034,789) ​ Reconciling items: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ State income taxes ​ ​ 5,033 ​ ​ ​ (72,280) ​ ​ ​ 72,280 ​ Non-controlling interest ​ ​ (1,788,347) ​ ​ ​ 20,294,890 ​ ​ ​ 18,721,170 ​ (Income) loss at OpCo ​ ​ (7,139,168) ​ ​ ​ 33,670,062 ​ ​ ​ 15,130,685 ​ Change in valuation allowance - federal ​ ​ (363,132) ​ ​ ​ (749,866) ​ ​ ​ 80,520 ​ Change in valuation allowance - state ​ ​ (40,626) ​ ​ ​ 168,393 ​ ​ ​ (70,441) ​ Other, net ​ ​ 472,825 ​ ​ ​ (231,440) ​ ​ ​ — ​ Provision for (benefit from) income taxes ​ $ 74,100 ​ ​ $ (885,193) ​ ​ $ 899,425 ​
Schedule of components of deferred tax assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Deferred tax asset ​ ​ ​ ​ ​ ​ Outside basis in OpCo ​ $ 6,641,452 ​ $ 17,624,909 ​ $ 20,050,732 Federal tax loss carryforwards ​ ​ 12,296,282 ​ ​ 1,675,957 ​ ​ — State tax loss carryforwards ​ ​ 1,789,961 ​ ​ 238,559 ​ ​ — Deferred tax asset ​ ​ 20,727,695 ​ ​ 19,539,425 ​ ​ 20,050,732 Valuation allowance ​ ​ (20,727,695) ​ ​ (19,539,425) ​ ​ (20,050,732) Net deferred tax asset ​ $ — ​ $ — ​ $ — Deferred tax liability ​ ​ ​ ​ ​ ​ ​ ​ ​ Derivative instruments and other ​ ​ — ​ ​ — ​ ​ — Net deferred tax liability ​ $ — ​ $ — ​ $ — 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, 2021
COMMITMENTS AND CONTINGENCIES.
Schedule of future minimum lease commitments	​ ​ ​ ​ ​ Years Ending December 31, ​ 2022 ​ $ 486,045 2023 ​ 487,787 2024 ​ 488,725 2025 ​ 497,033 2026 ​ ​ 507,648 Thereafter ​ ​ 1,219,267 Total ​ $ 3,686,505

SUPPLEMENTAL OIL AND GAS RESE_2

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2021
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, ​ 2021 ​ 2020 Oil, natural gas and NGL interests ​ ​ ​ ​ ​ ​ Proved properties ​ $ 1,051,111,311 ​ $ 923,413,606 Unevaluated properties ​ ​ 153,284,173 ​ ​ 225,681,626 Total oil, natural gas and NGL interests ​ 1,204,395,484 ​ 1,149,095,232 Accumulated depreciation, depletion, accretion and impairment ​ (663,603,142) ​ (628,102,279) Net oil, natural gas and NGL interests capitalized ​ $ 540,792,342 ​ $ 520,992,953
Schedule of costs incurred in oil and natural gas activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Acquisition costs ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved properties ​ $ 55,300,252 ​ $ 41,476,733 ​ $ 104,199,579 Unevaluated properties ​ ​ — ​ ​ 74,263,481 ​ ​ 110,050,000 Total ​ 55,300,252 ​ 115,740,214 ​ 214,249,579 Development costs ​ ​ ​ Proved properties ​ — ​ — ​ — Total ​ — ​ — ​ — Total costs incurred on oil, natural gas and NGL activities ​ $ 55,300,252 ​ $ 115,740,214 ​ $ 214,249,579
Results of operations from oil, natural gas and natural gas liquids	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 Oil, natural gas and NGL revenues ​ $ 175,088,021 ​ $ 92,586,685 ​ $ 107,480,446 Lease bonus and other income ​ ​ 3,319,104 ​ ​ 345,771 ​ ​ 2,477,145 Production and ad valorem taxes ​ (10,480,481) ​ (6,389,231) ​ (7,719,949) Depreciation and depletion expense ​ (36,797,881) ​ (47,988,796) ​ (52,118,367) Impairment of oil and natural gas properties ​ — ​ (251,558,557) ​ (169,150,255) Marketing and other deductions ​ (12,048,643) ​ (9,376,375) ​ (8,145,397) Results of operations from oil, natural gas and NGLs ​ $ 119,080,120 ​ $ (222,380,503) ​ $ (127,176,377)
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, 2019 ​ 10,795 ​ 127,261 ​ 5,646 ​ 37,651 Revisions of previous estimates (1) ​ 849 ​ 25,398 ​ 684 ​ 5,766 Purchase of minerals in place (2) ​ 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 Revisions of previous estimates (1) ​ 18 ​ (2,256) ​ (2) ​ (359) Purchase of minerals in place (3) ​ 1,367 ​ 15,637 ​ 313 ​ 4,286 Production ​ (1,409) ​ (17,890) ​ (681) ​ (5,072) Net proved reserves at December 31, 2020 ​ 12,294 ​ 144,233 ​ 6,085 ​ 42,418 Revisions of previous estimates (1) ​ 251 ​ 24,079 ​ 780 ​ 5,044 Purchase of minerals in place (4) ​ 1,310 ​ 8,537 ​ 519 ​ 3,252 Production ​ (1,344) ​ (19,085) ​ (715) ​ (5,240) Net proved reserves at December 31, 2021 ​ 12,511 ​ 157,764 ​ 6,669 ​ 45,474 ​ ​ ​ ​ ​ ​ ​ ​ ​ Net proved developed reserves ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ 11,303 ​ 141,181 ​ 6,079 ​ 40,912 December 31, 2020 ​ 12,294 ​ 144,233 ​ 6,085 ​ 42,418 December 31, 2021 ​ 12,511 ​ 157,764 ​ 6,669 ​ 45,474 ​ ​ ​ ​ ​ ​ ​ ​ ​ Net proved undeveloped reserves ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ 1,015 ​ 7,561 ​ 376 ​ 2,651 December 31, 2020 ​ — ​ — ​ — ​ — December 31, 2021 ​ — ​ — ​ — ​ — (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 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. (3) Includes the acquisition of mineral and royalty interests for a total of $41.5 million. The acquisition consists of mineral and royalty interests primarily in the Delaware Basin, DJ Basin, Haynesville, STACK and Eagle Ford. (4) Includes the acquisition of mineral and royalty interests for a total of $55.3 million, primarily consisting of mineral and royalty interests in the Permian Basin, Mid-Continent, Haynesville and other leading U.S. basins. ​
Schedule of standardized measure related to proved oil, natural gas and natural gas liquids reserves	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, ​ 2021 ​ 2020 ​ 2019 Future cash inflows ​ $ 1,335,917 ​ $ 705,356 ​ $ 1,025,430 Future production costs ​ ​ (100,947) ​ ​ (55,897) ​ ​ (78,061) Future state margin taxes ​ ​ (42,965) ​ ​ (22,688) ​ ​ (32,377) Future income tax expense ​ ​ — ​ ​ — ​ ​ (33,235) Future net cash flows ​ ​ 1,192,005 ​ ​ 626,771 ​ ​ 881,757 Less 10% annual discount to reflect timing of cash flows ​ ​ (665,390) ​ ​ (341,775) ​ ​ (481,786) Standard measure of discounted future net cash flows ​ $ 526,615 ​ $ 284,996 ​ $ 399,971
Schedule of changes in standardized measure related to proved oil, natural gas and natural gas liquids reserves	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, ​ ​ 2021 ​ 2020 ​ 2019 Standardized measure - beginning of year ​ $ 284,996 ​ $ 399,971 ​ $ 398,367 Sales, net of production costs ​ ​ (152,751) ​ ​ (76,821) ​ ​ (93,942) Net changes of prices and production costs related to future production ​ ​ 225,868 ​ ​ (127,838) ​ ​ (72,875) Revisions of previous quantity estimates, net of related costs ​ ​ 60,517 ​ ​ (2,501) ​ ​ 56,666 Net changes in state margin taxes ​ ​ (8,665) ​ ​ 4,314 ​ ​ 191 Net changes in income taxes ​ ​ — ​ ​ 13,480 ​ ​ 3,752 Accretion of discount ​ ​ 25,743 ​ ​ 38,927 ​ ​ 42,808 Purchases of reserves in place ​ ​ 40,545 ​ ​ 46,007 ​ ​ 59,953 Timing differences and other ​ ​ 50,362 ​ ​ (10,543) ​ ​ 5,051 Standardized measure - end of year ​ $ 526,615 ​ $ 284,996 ​ $ 399,971

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Details)	12 Months Ended
	Dec. 31, 2021segment
Segment Reporting
Number of operating units	1
Number of reporting units	1

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -Other Disclosures (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Accounts Receivable
Allowance for doubtful accounts receivable	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2021
Minimum
Oil and natural gas properties
Useful life	3 years
Maximum
Oil and natural gas properties
Useful life	7 years

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Oil and Natural Gas Properties
Gain (loss) recorded on disposition of oil, natural gas and natural gas liquid properties	$ 0	$ 0	$ 0
Number of exploratory activities pending determination	0	0	0
Exploratory costs charged	$ 0	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Taxes
Uncertain tax positions	$ 0	$ 0	$ 0
Interest and penalties	$ 0	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration of Credit Risk (Details) - Sales - Customer - item	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Concentration of Credit Risk
Number of significant purchasers	1
Operator 1
Concentration of Credit Risk
Purchaser percentage	6.00%	7.10%	6.00%

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue from Contracts with Customers (Details)	12 Months Ended
	Dec. 31, 2021
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

ACQUISITIONS, JOINT VENTURES _2

ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY - Acquisitions (Details)	Feb. 08, 2022USD ($)$ / sharesshares	Dec. 07, 2021USD ($)item	Jul. 29, 2021$ / sharesshares	Mar. 10, 2021USD ($)	Apr. 17, 2020USD ($)aitemshares	Dec. 12, 2019ashares	Nov. 06, 2019USD ($)a	Mar. 25, 2019ashares	Dec. 31, 2021USD ($)shares	Dec. 31, 2020USD ($)	Jun. 19, 2019USD ($)
Acquisitions
Investments | $									$ 4,738,822	$ 5,134,951
Offering costs | $	$ 930,824								$ 900,000
Kimbell Tiger Acquisition Corporation
Acquisitions
Joint Venture contributions | $	$ 14,100,000
Common units issued for equity offering (in units)	23,000,000		23,000,000						14,100,000
Share price (in dollar per share) | $ / shares	$ 10		$ 10
Warrant share price (in dollar per share) | $ / shares	$ 11.50		$ 11.50
Common Units
Acquisitions
Common units issued for equity offering (in units)									4,312,500
Underwriters option to purchase additional units | Kimbell Tiger Acquisition Corporation
Acquisitions
Common units issued for equity offering (in units)			3,000,000
Nail Bay Royalties
Acquisitions
Purchase price cash, gross | $				$ 500,000
Caritas Royalty Fund, LLC
Acquisitions
Transaction value of acquisition | $		$ 54,600,000
Number of gross producing wells being operated. | item		26,000
Phillips Acquisition
Acquisitions
Gross acres acquired (in acres) | a								866,528
Net royalty acres acquired (in acres) | a								12,210
Phillips Acquisition | OpCo Units
Acquisitions
Business Acquisition issuance of common units								9,400,000
Phillips Acquisition | Class B Common Units
Acquisitions
Business Acquisition issuance of common units								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. | Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP.
Acquisitions
Investments | $									$ 5,100,000		$ 5,100,000
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC
Acquisitions
Purchase price cash, gross | $					$ 95,000,000
Net royalty acres acquired (in acres) | a					2,160
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC | Minimum
Acquisitions
The number of operators acquired | item					90
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC | OpCo Units
Acquisitions
Business Acquisition issuance of common units					2,497,134
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC | Common Units
Acquisitions
Business Acquisition issuance of common units					2,224,358
Oklahoma Property Acquisition
Acquisitions
Purchase price cash, gross | $							$ 9,900,000
Gross acres acquired (in acres) | a							279,680
Net royalty acres acquired (in acres) | a							186
Buckhorn Acquisition
Acquisitions
Gross acres acquired (in acres) | a						86,005
Net royalty acres acquired (in acres) | a						405
Buckhorn Acquisition | OpCo Units
Acquisitions
Business Acquisition issuance of common units						2,169,348
Buckhorn Acquisition | Class B
Acquisitions
Business Acquisition issuance of common units						2,169,348

DERIVATIVES (Details)

DERIVATIVES (Details)	12 Months Ended
	Dec. 31, 2021USD ($)$ / bblbblMMBbls	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Jan. 27, 2021USD ($)
Derivatives
Daily oil and natural gas production (as a percent)	32.00%
Change in fair values of derivative instruments
Beginning fair value of commodity derivative instruments | $	$ (6,280,863)	$ 804,501	$ 4,227,946
Loss on derivative instruments | $	(41,240,942)	(2,450,541)	(1,732,321)
Net cash (received) paid on settlements of derivative instruments | $	20,897,159	(4,634,823)	(1,691,124)
Ending fair value of commodity derivative instruments | $	(26,624,646)	(6,280,863)	804,501
Assets:
Current asset | $	166,307
Derivative assets | $	1,590,501
Liabilities:
Current liability | $	(24,190,678)	(3,113,178)
Long-term liability | $	(4,190,776)	(3,167,685)
Derivative assets (liabilities) | $	(26,624,646)	$ (6,280,863)	$ 804,501
Interest Rate Swap
Derivatives
Derivative, Notional Amount | $	$ 150,000,000			$ 150,000,000
Derivative hedging of outstanding debt (as a percent)	69.00%
Interest rate swap (as a percent)				3.90%
Commodity derivative contracts | $	$ 1,800,000
Liabilities:
Derivative Asset | $	$ 1,756,808
Oil Price Swaps - January 2022 - December 2022
Derivatives
Notional Volumes | bbl	500,552
Weighted Average Fixed Price | $ / bbl	41.86
Oil Price Swaps - January 2023 - December 2023
Derivatives
Notional Volumes | bbl	303,411
Weighted Average Fixed Price | $ / bbl	59.35
Natural Gas Price Swaps - January 2022 - December 2022
Derivatives
Notional Volumes | MMBbls	6,357,449
Weighted Average Fixed Price | $ / bbl	2.46
Natural Gas Price Swaps - January 2023 - December 2023
Derivatives
Notional Volumes | MMBbls	4,245,899
Weighted Average Fixed Price | $ / bbl	2.90
Minimum | Oil Price Swaps - January 2022 - December 2022
Derivatives
Weighted Average Fixed Price | $ / bbl	35.65
Minimum | Oil Price Swaps - January 2023 - December 2023
Derivatives
Weighted Average Fixed Price | $ / bbl	53.38
Minimum | Natural Gas Price Swaps - January 2022 - December 2022
Derivatives
Weighted Average Fixed Price | $ / bbl	2.23
Minimum | Natural Gas Price Swaps - January 2023 - December 2023
Derivatives
Weighted Average Fixed Price | $ / bbl	2.52
Maximum | Oil Price Swaps - January 2022 - December 2022
Derivatives
Weighted Average Fixed Price | $ / bbl	46
Maximum | Oil Price Swaps - January 2023 - December 2023
Derivatives
Weighted Average Fixed Price | $ / bbl	63
Maximum | Natural Gas Price Swaps - January 2022 - December 2022
Derivatives
Weighted Average Fixed Price | $ / bbl	2.70
Maximum | Natural Gas Price Swaps - January 2023 - December 2023
Derivatives
Weighted Average Fixed Price | $ / bbl	3.28

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Commodity Derivative contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts liabilities	$ (28,381,454)	$ (6,280,863)
Commodity Derivative contract | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts liabilities	(28,381,454)	$ (6,280,863)
Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative contracts	1,800,000
Derivative contracts assets	1,756,808
Interest Rate Swap | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets	$ 1,756,808

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
OIL AND NATURAL GAS PROPERTIES
Proved properties	$ 1,051,111,311	$ 923,413,606
Unevaluated properties	153,284,173	225,681,626
Less: accumulated depreciation, depletion, and impairment	(663,603,142)	(628,102,279)
Total oil and natural gas properties, net	540,792,342	520,992,953
Transfer to full cost pool		48,600,000
Percent of proved undeveloped reserves of estimated proved reserves (as a percent)			6.10%
Impairment of oil and natural gas properties	$ 0	$ 251,558,557	$ 169,150,255

LEASES (Details)

LEASES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
LEASES
Operating lease weighted average remaining lease term	7 years 4 months 6 days
Operating lease weighted average discount rate (as a percent)	6.75%
Operating lease expense	$ 400,000	$ 500,000	$ 300,000
2022	486,045
2023	487,787
2024	488,725
2025	497,033
2026	507,648
Thereafter	1,219,267
Total operating leases	3,686,505
Less Imputed Interest	(823,006)
Total	$ 2,863,499

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($)	Dec. 08, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Nov. 01, 2021	Dec. 07, 2020	Feb. 08, 2017
Long-term debt
Amortization of Debt Issuance Costs		$ 1,556,769	$ 1,108,685	$ 1,050,278
Borrowings of debt		136,565,769	162,614,665	$ 12,825,933
Repayment of debt		91,000,000	91,200,000
Revolving credit facility
Long-term debt
Revolving credit facility maximum borrowings	$ 265,000,000					$ 225,000,000
Revolving credit facility increased maximum borrowing capacity if certain conditions are met	$ 500,000,000
Amortization of Debt Issuance Costs			$ 500,000
Revolving credit facility outstanding		$ 217,100,000
Floor margin	0.25%
Permitted numerator subjected to cash	$ 25,000,000
Interest rate on outstanding borrowings (as a percent)		3.86%
Borrowing base	$ 265,000,000				$ 275,000,000
Amount of applicable margin increase for each applicable level (as a percent)	1.00%
Commitment fees (as a percent)	0.50%
Borrowings of debt		$ 136,600,000
Repayment of debt		$ 91,000,000
Revolving credit facility | LIBOR
Long-term debt
Variable rate		LIBOR
Margin (as a percent)		3.75%
Revolving credit facility | Prime
Long-term debt
Margin (as a percent)		2.75%
Revolving credit facility | Maximum
Long-term debt
Debt to EBITDAX ratio	400.00%						350.00%
Revolving credit facility | Maximum | LIBOR
Long-term debt
Margin (as a percent)	4.00%
Revolving credit facility | Maximum | Prime
Long-term debt
Margin (as a percent)	3.00%
Revolving credit facility | Minimum
Long-term debt
Debt to EBITDAX ratio	350.00%
Current assets to current liabilities ratio							100.00%
Revolving credit facility | Minimum | LIBOR
Long-term debt
Margin (as a percent)	3.00%
Revolving credit facility | Minimum | Prime
Long-term debt
Margin (as a percent)	2.00%

PREFERRED UNITS - Other (Detail

PREFERRED UNITS - Other (Details) - USD ($)	Dec. 07, 2021	Jul. 07, 2021	Feb. 12, 2020	Jul. 31, 2018	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Preferred units
Temporary equity, outstanding (in units)					0	55,000
Series A preferred units deemed distributions					$ 11,249,969	$ 7,810,588	$ 13,878,336
Series A Preferred Units
Preferred units
Redemption of Series A preferred units	25,000	30,000	55,000		55,000
Percentage of Series A preferred units redeemed		55.00%	50.00%
Unit price (in dollars per unit)	$ 1,240.25	$ 1,202.51	$ 1,110.72
Series A preferred units redemption price	$ 31,000,000	$ 36,100,000	$ 61,100,000
Deemed distribution amount			$ 5,700,000
Temporary equity, outstanding (in units)		25,000
Series A preferred units deemed distributions					$ 3,800,000
Series A Preferred Units | Minimum
Preferred units
Percent of consideration transferred to carrying value of units (as a percent)			50.00%
Percent of consideration transferred to original intrinsic value of units (as a percent)			50.00%
Series A Preferred Stock
Preferred units
Series A preferred units deemed distributions					$ 3,600,000
Affiliates of Apollo Capital Management, L.P.
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%
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%

PREFERRED UNITS - Rollforward (

PREFERRED UNITS - Rollforward (Details) - Series A Preferred Units - shares	Dec. 07, 2021	Jul. 07, 2021	Feb. 12, 2020	Dec. 31, 2021
Preferred units rollforward
Balance at beginning of period				55,000
Redemption of Series A preferred units	(25,000)	(30,000)	(55,000)	(55,000)

UNITHOLDERS' EQUITY AND PARTN_3

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Details) - USD ($)	1 Months Ended		3 Months Ended												12 Months Ended
	Nov. 30, 2021	Jan. 31, 2020	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020
Common units
Units issued (in units)			47,162,773				38,918,689								47,162,773	38,918,689
Units outstanding (in units)			47,162,773				38,918,689								47,162,773	38,918,689
Repayment of debt															$ 91,000,000	$ 91,200,000
Capital rollforward
Unitholders' capital, beginning balance (in units)						38,918,689									38,918,689
Unitholders' capital, ending balance (in units)			47,162,773				38,918,689								47,162,773	38,918,689
Cash distributions declared and paid (in dollars per unit)			$ 0.37	$ 0.37	$ 0.31	$ 0.27	$ 0.19	$ 0.19	$ 0.13	$ 0.17	$ 0.38	$ 0.42	$ 0.39	$ 0.37
Common Units
Common units
Units issued (in units)			47,162,773												47,162,773
Units outstanding (in units)			47,162,773				38,918,689								47,162,773	38,918,689
Capital rollforward
Unitholders' capital, beginning balance (in units)						38,918,689									38,918,689
Common units issued for equity offering (in units)															4,312,500
Conversion of Class B Units (in units)															3,168,202
Common units issued under the LTIP (in units)															936,567
Restricted units repurchased for tax withholding (in units)															(173,185)
Unitholders' capital, ending balance (in units)			47,162,773				38,918,689								47,162,773	38,918,689
Class B
Common units
Units outstanding (in units)			17,611,579				20,779,781								17,611,579	20,779,781
Capital rollforward
Unitholders' capital, beginning balance (in units)						20,779,781									20,779,781
Conversion of Class B Units (in units)															(3,168,202)
Unitholders' capital, ending balance (in units)			17,611,579				20,779,781								17,611,579	20,779,781
Cash distributions (as a percent)															2.00%
Additional consideration paid per unit (in dollars per unit)															$ 0.05
Public Offering
Common units
Units issued (in units)	4,312,500	5,000,000
Proceeds from equity offering	$ 57,700,000	$ 73,600,000
Repayment of debt	$ 56,000,000	$ 70,000,000
Underwriters option to purchase additional units
Common units
Units outstanding (in units)		750,000
Capital rollforward
Unitholders' capital, ending balance (in units)		750,000

EARNINGS (LOSS) PER COMMON UN_3

EARNINGS (LOSS) PER COMMON UNIT (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings per unit
Net income (loss) attributable to common units	$ 22,615,021	$ (167,350,893)	$ (83,032,282)
Net income and distributions and accretion on Series A preferred units attributable to noncontrolling interest	8,496,104	(96,642,334)	(89,148,428)
Diluted net income (loss) attributable to common units	$ 31,111,125	$ (167,350,893)	$ (83,032,282)
Weighted average number of common units outstanding Basic (in units)	40,400,907	34,530,398	21,192,714
Weighted average number of common units outstanding Diluted (in units)	60,957,824	34,530,398	21,192,714
Net income (loss) attributable to common units per unit (basic)	$ 0.56	$ (4.85)	$ (3.92)
Net income (loss) attributable to common units per unit (diluted)	$ 0.51	$ (4.85)	$ (3.92)
Restricted Units
Earnings per unit
Weighted average number of common units outstanding (in units)	1,717,310
Anti-dilutive options outstanding		1,276,546	739,479
Unvested Restricted Units
Earnings per unit
Weighted average number of common units outstanding (in units)	1,717,310
Class B
Earnings per unit
Weighted average number of common units outstanding (in units)	18,839,607

UNIT-BASED COMPENSATION (Detail

UNIT-BASED COMPENSATION (Details) - Long-Term Incentive Plan - $ / shares	Sep. 23, 2018	Dec. 31, 2021	Dec. 31, 2020
Unit-based compensation
Additional common units authorized for issuance	4,541,600
Vesting period		3 years
First Anniversary
Unit-based compensation
Vesting percent		33.30%
Second Anniversary
Unit-based compensation
Vesting percent		33.30%
Third Anniversary
Unit-based compensation
Vesting percent		33.30%
Restricted Units
Unvested Units
Unvested at beginning of period (in units)		1,276,546
Awarded (in units)		936,567
Vesting (in units)		(652,214)
Unvested at end of period (in units)		1,560,899	1,276,546
Unvested Weighted Average Grant-Date Fair Value
Unvested at beginning of period (in dollars per unit)		$ 13.604
Awarded (in dollars per unit)		10.350
Vesting (in dollars per unit)		14.905
Unvested at end of period (in dollars per unit)		$ 11.108	$ 13.604
Weighted Average Remaining Contractual Term
Unvested contractual term, at end of period		1 year 9 months 9 days	1 year 9 months 13 days

INCOME TAXES - (Details)

INCOME TAXES - (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
INCOME TAXES
Texas franchise tax (as a percent)	0.75%
Effective income tax rate (as a percent)	0.17%
(Benefit from) provision for income taxes	$ (74,100)	$ 885,193	$ (899,425)

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current
Federal	$ 69,067	$ (812,913)	$ 812,913
State	5,033	(72,280)	86,512
Total Current	74,100	(885,193)	899,425
Deferred
Provision for (benefit from) income taxes	$ 74,100	$ (885,193)	$ 899,425

INCOME TAXES - Reconciliation (

INCOME TAXES - Reconciliation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of the provision for income taxes at statutory rates to the provision for income taxes at the effective tax rate
Net income (loss) before taxes	$ 42,511,974	$ (256,975,963)	$ (157,308,520)
Statutory rate (as a percent)	21.00%	21.00%	21.00%
Income tax provision (benefit) computed at statutory rate	$ 8,927,515	$ (53,964,952)	$ (33,034,789)
State income taxes	5,033	(72,280)	72,280
Non-controlling interest	(1,788,347)	20,294,890	18,721,170
(Income) loss at OpCo	(7,139,168)	33,670,062	15,130,685
Change in valuation allowance - federal	(363,132)	(749,866)	80,520
Change in valuation allowance - state	(40,626)	168,393	(70,441)
Other, net	472,825	(231,440)
Provision for (benefit from) income taxes	$ 74,100	$ (885,193)	$ 899,425

INCOME TAXES - Deferred Taxes (

INCOME TAXES - Deferred Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Deferred tax asset
Outside basis in OpCo	$ 6,641,452	$ 17,624,909	$ 20,050,732
Federal tax loss carryforwards	12,296,282	1,675,957
State tax loss carryforwards	1,789,961	238,559
Deferred tax assets	20,727,695	19,539,425	20,050,732
Valuation allowance	(20,727,695)	(19,539,425)	(20,050,732)
Deferred tax liability
Outside basis investment in operating company valuation allowance	20,700,000
Uncertain tax positions	$ 0	$ 0	$ 0

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($)	Feb. 08, 2022	Jul. 29, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transactions
Offering costs	$ 930,824		$ 900,000
Kimbell Tiger Acquisition Corporation
Related Party Transactions
Common units issued for equity offering (in units)	23,000,000	23,000,000	14,100,000
Share price (in dollar per share)	$ 10	$ 10
Underwritten Public Offering | Kimbell Tiger Acquisition Corporation
Related Party Transactions
Common units issued for equity offering (in units)	3,000,000
BJF Royalties
Related Party Transactions
Payments made to related parties			$ 0
K3 Royalties
Related Party Transactions
Payments made to related parties			120,000
Nail Bay Royalties
Related Party Transactions
Payments made to related parties			301,314
Duncan Management
Related Party Transactions
Payments made to related parties			548,480
Director And Officer Insurance To Partnership At Higginbotham Insurance Financial Services
Related Party Transactions
Related Party Transaction, Amounts of Transaction			22,160	$ 20,160	$ 18,900
Related Party Transactions, Annual Insurance Premium Expense			$ 555,640	$ 440,160	$ 350,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
COMMITMENTS AND CONTINGENCIES.
2022	$ 486,045
2023	487,787
2024	488,725
2025	497,033
2026	507,648
Thereafter	1,219,267
Total operating leases	3,686,505
Operating lease liabilities, excluding current portion	2,561,274	$ 2,848,452
Operating Lease, Expense	$ 400,000	$ 500,000	$ 300,000

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($)

Feb. 24, 2022

Feb. 08, 2022

Feb. 07, 2022

Jan. 28, 2022

Jan. 27, 2022

Jan. 21, 2022

Jan. 14, 2022

Jul. 29, 2021

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2019

Dec. 08, 2020

Dec. 07, 2020

Subsequent events

Distributions on Series A redeemable preferred units

$ 2,800,012

$ 4,812,509

$ 7,700,000

Distributions to Class B unitholders

76,780

91,869

$ 94,429

Common units issued for equity offering

$ 57,522,440

$ 73,601,668

Common Units

Subsequent events

Common units issued for equity offering (in units)

4,312,500

Subsequent Event | Class B Common Units

Subsequent events

Distributions to Class B unitholders

$ 17,610

Percentage Of Respective Class Contribution Made

2.00%

Subsequent Event | Common Units

Subsequent events

Cash distributions declared (in dollars per unit)

$ 0.37

Subsequent Event | Certain Employees, Directors and Consultants

Subsequent events

Cash bonuses awarded

$ 2,200,000

Subsequent Event | Certain Employees, Directors and Consultants | Restricted Units

Subsequent events

Units issued for bonus compensation

963,835

Revolving credit facility

Subsequent events

Line of Credit Facility, Maximum Borrowing Capacity

$ 265,000,000

$ 225,000,000

Revolving credit facility | Subsequent Event

Subsequent events

Draw downs

$ 5,000,000

$ 1,200,000

$ 12,900,000

Kimbell Tiger Acquisition Corporation

Subsequent events

Common units issued for equity offering (in units)

23,000,000

23,000,000

14,100,000

Share price (in dollar per share)

$ 10

$ 10

Kimbell Tiger Acquisition Corporation | Subsequent Event

Subsequent events

Common units issued for equity offering (in units)

23,000,000

Share price (in dollar per share)

$ 10

Underwritten Public Offering | Kimbell Tiger Acquisition Corporation

Subsequent events

Common units issued for equity offering (in units)

3,000,000

Underwritten Public Offering | Kimbell Tiger Acquisition Corporation | Subsequent Event

Subsequent events

Common units issued for equity offering (in units)

3,000,000

SUPPLEMENTAL OIL AND GAS RESE_3

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Other Disclosures (Details)	12 Months Ended
	Dec. 31, 2021USD ($)segment	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Number of reporting segments | segment	1
Oil, natural gas and NGL interests
Proved properties	$ 1,051,111,311	$ 923,413,606
Unevaluated properties	153,284,173	225,681,626
Total oil, natural gas and NGL interest	1,204,395,484	1,149,095,232
Accumulated depreciation, depletion and impairment	(663,603,142)	(628,102,279)
Net oil, natural gas and NGL interests capitalized	540,792,342	520,992,953
Acquisition costs
Proved properties	55,300,252	41,476,733	$ 104,199,579
Unevaluated properties		74,263,481	110,050,000
Total	55,300,252	115,740,214	214,249,579
Developed costs
Total costs incurred on oil, natural gas and NGL activities	55,300,252	115,740,214	214,249,579
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities
Oil, natural gas and NGL revenue	175,088,021	92,586,685	107,480,446
Lease bonus and other income	3,319,104	345,771	2,477,145
Production and ad valorem taxes	(10,480,481)	(6,389,231)	(7,719,949)
Depreciation and depletion expense	(36,797,881)	(47,988,796)	(52,118,367)
Impairment of oil and natural properties		(251,558,557)	(169,150,255)
Marketing and other deductions	(12,048,643)	(9,376,375)	(8,145,397)
Results of operations form oil, natural gas and NGLs	$ 119,080,120	$ (222,380,503)	$ (127,176,377)

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, 2021USD ($)MBblsMMcf	Dec. 31, 2020USD ($)MMcfMBbls	Dec. 31, 2019USD ($)itemMMcfMBbls
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	42,418	43,563	37,651
Revisions of previous estimates	5,044	(359)	5,766
Purchase of minerals in place	3,252	4,286	4,661
Production	(5,240)	(5,072)	(4,515)
Net proved reserves at end of period	45,474	42,418	43,563
Net Proved Developed Reserves	45,474	42,418	40,912
Net Proved Undeveloped Reserves			2,651
Crude Oil and Condensate
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	12,294	12,318	10,795
Revisions of previous estimates	251	18	849
Purchase of minerals in place	1,310	1,367	1,787
Production	(1,344)	(1,409)	(1,113)
Net proved reserves at end of period	12,511	12,294	12,318
Net Proved Developed Reserves	12,511	12,294	11,303
Net Proved Undeveloped Reserves			1,015
Natural Gas
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period | MMcf	144,233	148,742	127,261
Revisions of previous estimates | MMcf	24,079	(2,256)	25,398
Purchase of minerals in place | MMcf	8,537	15,637	13,129
Production | MMcf	(19,085)	(17,890)	(17,046)
Net proved reserves at end of period | MMcf	157,764	144,233	148,742
Net Proved Developed Reserves | MMcf	157,764	144,233	141,181
Net Proved Undeveloped Reserves | MMcf			7,561
Natural Gas Liquids
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	6,085	6,455	5,646
Revisions of previous estimates	780	(2)	684
Purchase of minerals in place	519	313	686
Production	(715)	(681)	(561)
Net proved reserves at end of period	6,669	6,085	6,455
Net Proved Developed Reserves	6,669	6,085	6,079
Net Proved Undeveloped Reserves			376
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 | $	$ 55.3		$ 103.8
Number of packages of diverse mineral and royalty interests acquired | item			3
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
Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $		$ 41.5

SUPPLEMENTAL OIL AND GAS RESE_5

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Standardized Measure (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Standardized Measure
Future cash inflows	$ 1,335,917	$ 705,356	$ 1,025,430
Future production costs	(100,947)	(55,897)	(78,061)
Future state margin taxes	(42,965)	(22,688)	(32,377)
Future income tax expense			(33,235)
Future net cash flows	1,192,005	626,771	881,757
Less 10% annual discount to reflect timing of cash flows	(665,390)	(341,775)	(481,786)
Standard measure of discounted future net cash flows	$ 526,615	$ 284,996	$ 399,971	$ 398,367

SUPPLEMENTAL OIL AND GAS RESE_6

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Average Market Prices (Details) - $ / bbl	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Crude Oil and Condensate
Average Sales Prices
Average sales prices	66.56	39.57	55.69
Natural Gas
Average Sales Prices
Average sales prices	3.60	1.99	2.58

SUPPLEMENTAL OIL AND GAS RESE_7

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Changes in Standardized Measure (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Changes in Standardized Measure
Standardized measure - beginning of year	$ 284,996	$ 399,971	$ 398,367
Sales, net of production costs	(152,751)	(76,821)	(93,942)
Net changes of prices and production costs related to future production	225,868	(127,838)	(72,875)
Revisions of previous quantity estimates, net of related costs	60,517	(2,501)	56,666
Net changes in state margin taxes	(8,665)	4,314	191
Net changes in income taxes		13,480	3,752
Accretion of discount	25,743	38,927	42,808
Purchases of reserves in place	40,545	46,007	59,953
Timing differences and other	50,362	(10,543)	5,051
Standardized measure - end of year	$ 526,615	$ 284,996	$ 399,971