Kimbell Royalty Partners (KRP) 10-K/A 8 Nov 24 2023 FY Annual report (amended) Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Feb. 16, 2024	Jun. 30, 2023
Document Information
Document Type	10-K/A
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 898.8
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	true
Document Financial Statement Restatement Recovery Analysis [Flag]	false
Entity Shell Company	false
Entity Central Index Key	0001657788
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Auditor Name	GRANT THORNTON LLP
Auditor Firm ID	248
Auditor Location	Dallas, Texas
Amendment Flag	true
Amendment Description	Kimbell Royalty Partners, LP ("our Partnership," "we," "our," "us" or like terms) is filing this Amendment No. 1 on Form 10-K/A (this "Amendment") to our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, which was filed on February 21, 2024 (the "Original Form 10-K") to make certain changes described below. Background We are organized in a structure that is commonly referred to as an "Up-C" structure. Our direct subsidiary, Kimbell Royalty Operating, LLC ("OpCo"), is owned partially by us and partially by other investors. The other investors of OpCo are permitted to exchange their interest in OpCo, together with a Class B unit of the Partnership, into an equal number of our common units. The ownership interest by such other investors in OpCo is shown as a non-controlling interest in our consolidated financial statements. In connection with the preparation of our unaudited interim consolidated financial statements for the three and nine months ended September 30, 2024, we identified an error in the application of accounting guidance related to the changes in ownership of OpCo. We previously accounted for the changes in ownership of OpCo by reallocating the non-controlling interest associated with such changes at fair value. Under ASC 810-10, changes in ownership of a consolidated subsidiary that is less than wholly owned (such as OpCo) should be accounted for by adjusting the carrying value of such non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the noncontrolling interest is adjusted should be recognized in equity attributable to the parent. We evaluated the error and determined that they did not result in a material misstatement of our previously issued consolidated financial statements. In making this determination, we noted that the error (i) only resulted in a reclass of amounts between components within unitholders' equity (specifically, from Common Units to Non-Controlling Interest in OpCo) and (ii) did not have any impact on the total unitholders' equity amount in our consolidated balance sheets, the total amount in our consolidated statement of changes in unitholders' equity or any other portion of our financial statements. Moreover, the error had no impact on items in our consolidated statement of operations or statement of cash flows, including any information related to revenues, net income, net income attributable to common units, earnings per unit and other items. The error similarly did not have an impact on any of our key performance indicators and non-GAAP metrics, included Adjusted EBITDA and cash available for distribution, nor did it have any impact on compliance with our material financial covenants under debt instruments or other contractual arrangements. However, in connection with the period-end close process, we identified a material weakness in our internal control over financial reporting and have concluded this material weakness was present as of December 31, 2023. Description of Amendment This Amendment amends the following items in our Original Form 10-K: • Cautionary Statement Regarding Forward-Looking Statements: We are providing certain updates to the forward-looking statements section of our Original Form 10-K. • Part II. Item 8. Financial Statements and Supplementary Data: We are updating the unitholders' equity portion of our consolidated balance sheet, as well as our consolidated statements of changes in unitholders' equity, to correct the error discussed above. In addition, we have added Note 18 (Correction of Immaterial Errors) to discuss the error. Our consolidated financial statements are included in this Amendment beginning on page F-1. • Part II. Item 9A. Controls and Procedures: We are amending this item to disclose the material weakness that was identified as a result of the error discussed above, and to revise our assessment of the effectiveness of our internal control over financial reporting and our disclosure controls and procedures to indicate that they were not effective as of December 31, 2023 because of the material weakness. We are also including a revised audit report of Grant Thornton LLP, our independent registered public accounting firm, on our internal control over financial reporting as of December 31, 2023. • Part IV. Item 15. Exhibits, Financial Statement Schedules: We are amending this item to include a new consent of Grant Thornton LLP and, as required by Rule 12b-15 under the Securities Act of 1934, as amended, to provide new currently dated certifications by our Chief Executive Officer and Chief Financial Officer pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act of 2002. The new consent is attached to this Amendment as Exhibit 23.1 and the new certifications are attached to this Amendment as Exhibits 31.1, 31.2, 32.1 and 32.2. We are also including new inline XBRL tagging. The only changes to the Original Form 10-K are those related to the matters described above. Except as described above, this Amendment does not amend, update or change any other item or disclosure in the Original Form 10-K and does not purport to reflect any information or event subsequent to the filing thereof. As such, this Amendment speaks only as of the date the Original Form 10-K was filed, and we have not undertaken to amend, update or change any information contained in the Original Form 10-K to give effect to any subsequent event, other than as expressly indicated in this Amendment. Accordingly, this Amendment should be read in conjunction with the Original Form 10-K and any subsequent filing with the SEC.
Common Units
Document Information
Entity Common Stock, Shares Outstanding		73,851,458
Class B
Document Information
Entity Common Stock, Shares Outstanding		20,847,295

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 30,992,670	$ 24,635,718
Oil, natural gas and NGL receivables	59,020,471	46,993,711
Derivative assets	11,427,735
Accounts receivable and other current assets	1,699,536	3,562,912
Total current assets	103,140,412	75,192,341
Property and equipment, net	589,895	953,781
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($222,712,844 and $207,695,343 excluded from depletion at December 31, 2023 and 2022, respectively)	2,048,690,088	1,465,985,718
Less: accumulated depreciation, depletion and impairment	(827,033,944)	(712,716,951)
Total oil and natural gas properties, net	1,221,656,144	753,268,767
Right-of-use assets, net	2,189,243	2,525,323
Derivative assets	2,888,051	754,786
Loan origination costs, net	7,325,471	3,004,104
Total assets	1,337,789,216	1,076,746,299
Current liabilities
Accounts payable	6,594,736	1,210,337
Other current liabilities	6,173,314	4,909,510
Derivative liabilities	208,710	12,646,720
Total current liabilities	12,976,760	18,766,567
Operating lease liabilities, excluding current portion	1,887,693	2,236,361
Derivative liabilities	60,094	432,142
Long-term debt	294,200,000	233,015,911
Other liabilities	197,917	322,917
Total liabilities	309,322,464	263,336,623
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (325,000 units and zero units issued and outstanding as of December 31, 2023 and 2022, respectively)	314,423,572
Redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		236,900,000
Kimbell Royalty Partners, LP unitholders' equity:
Common units (73,851,458 units and 64,231,833 units issued and outstanding as of December 31, 2023 and 2022, respectively)	555,809,000	463,751,910
Class B units (20,847,295 and 15,484,400 units issued and outstanding as of December 31, 2023 and 2022, respectively)	1,042,365	774,220
Total Kimbell Royalty Partners, LP unitholders' equity	556,851,365	464,526,130
Non-controlling interest in OpCo	157,191,815	111,983,546
Total unitholders' equity	714,043,180	576,509,676
Total liabilities, mezzanine equity and unitholders' equity	$ 1,337,789,216	1,076,746,299
Consolidated variable interest entities
Current assets
Investment held in trust		240,621,146
Prepaid expenses		35,201
Oil and natural gas properties
Cash		390,850
Current liabilities
Other current liabilities		512,725
Deferred underwriting commissions		$ 8,050,000

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2023	Dec. 31, 2022
CONSOLIDATED BALANCE SHEETS
Oil and natural gas properties excluded from depletion	$ 222,712,844	$ 207,695,343
Temporary equity, issued (in units)	325,000	0
Temporary equity, outstanding (in units)	325,000	0
Common units, issued (in units)	73,851,458	64,231,833
Common units, outstanding (in units)	73,851,458	64,231,833
Class B units, issued (in units)	20,847,295	15,484,400
Class B units, outstanding (in units)	20,847,295	15,484,400

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues	$ 267,584,785	$ 281,964,126	$ 175,088,021
Lease bonus and other income	5,594,855	3,073,609	3,319,104
Gain (loss) on commodity derivative instruments, net	20,888,972	(36,978,550)	(42,791,909)
Total revenues	294,068,612	248,059,185	135,615,216
Costs and expenses
Production and ad valorem taxes	20,326,477	16,238,814	10,480,481
Depreciation and depletion expense	96,477,003	50,086,414	36,797,881
Impairment of oil and natural gas properties	18,220,173	0	0
Marketing and other deductions	12,564,619	13,383,074	12,048,643
General and administrative expense	35,677,851	29,128,659	26,977,519
General and administrative expense consolidated variable interest entities	927,699	2,304,445
Total costs and expenses	184,193,822	111,141,406	86,304,524
Operating income	109,874,790	136,917,779	49,310,692
Other income (expense)
Equity income in affiliate		2,668,844	1,119,819
Interest expense	(25,950,600)	(13,818,310)	(9,182,103)
Loss on extinguishment of debt	(480,244)
Other (expense) income	(180,765)	4,043,530	1,263,566
Net income before income taxes	86,771,872	133,532,988	42,511,974
Income tax expense	3,766,302	2,738,702	74,100
Net income	83,005,570	130,794,286	42,437,874
Distribution and accretion on Series A preferred units	(6,310,215)		(11,249,969)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests	(16,464,890)	(18,822,552)	(8,496,104)
Distribution on Class B units	(88,786)	(42,243)	(76,780)
Net income attributable to common units of Kimbell Royalty Partners, LP	$ 60,141,679	$ 111,929,491	$ 22,615,021
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Net income per unit attributable to common units (basic) (in dollar per share)	$ 0.93	$ 1.75	$ 0.56
Net income per unit attributable to common units (diluted) (in dollar per share)	$ 0.91	$ 1.72	$ 0.51
Weighted average number of common units outstanding
Weighted average number of common units outstanding Basic (in units)	66,595,273	54,112,595	40,400,907
Weighted average number of common units outstanding Diluted (in units)	93,057,731	65,837,017	60,957,824
Consolidated variable interest entities
Other income (expense)
Interest earned on marketable securities in trust account	$ 3,508,691	$ 3,721,145
Oil, natural gas and NGL revenues
Revenues	267,584,785	281,964,126	$ 175,088,021
Lease bonus and other income
Revenues	$ 5,594,855	$ 3,073,609	$ 3,319,104

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY - USD ($)	Common Units	Class B Common Units	Non-controlling Interest in Opco	Non-controlling Interest in TGR	Total
Unitholders' capital, beginning balance at Dec. 31, 2020	$ 217,768,360	$ 1,038,989	$ 116,827,389		$ 335,634,738
Unitholders' capital, beginning balance (in units) at Dec. 31, 2020	38,918,689	20,779,781
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	$ 17,005,271	$ (158,410)	(17,005,271)		(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)
Change in ownership of consolidated subsidiaries, net	(12,295,407)		12,295,407		12,295,407
Net income	30,647,893		11,789,981		42,437,874
Unitholders' capital, ending balance at Dec. 31, 2021	$ 253,120,002	$ 880,579	94,849,200		348,849,781
Unitholders' capital, ending balance (in units) at Dec. 31, 2021	47,162,773	17,611,579
Increase (Decrease) in Unitholders' Capital
Common units issued for equity offering	$ 116,119,417				116,119,417
Common units issued for equity offering (in units)	6,900,000
Conversion of Class B units to common units	$ 50,598,886	$ (470,000)	(50,598,886)		(470,000)
Conversion of Class B units to common units (in units)	9,400,000	(9,400,000)
Restricted units repurchased for tax withholding	$ (3,344,828)				(3,344,828)
Restricted units repurchased for tax withholding (in units)	(193,604)
Forfeiture of restricted units	$ (19,813)				(19,813)
Forfeiture of restricted units (in units)	(1,171)
Units issued for acquisition		$ 363,641	120,292,459		120,656,100
Units issued for acquisition (in units)		7,272,821
Unit-based compensation	$ 11,107,639				11,107,639
Unit-based compensation (in units)	963,835
Distributions to unitholders	$ (107,402,294)		(19,323,523)		(126,725,817)
Distribution on Class B units	(42,243)				(42,243)
Proceeds from issuance of TGR public warrants				$ 11,500,000	11,500,000
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation	(17,412,732)		(3,002,114)	$ (11,500,000)	(31,914,846)
Change in ownership of consolidated subsidiaries, net	49,056,142		(49,056,142)		(49,056,142)
Net income	111,971,734		18,822,552		130,794,286
Unitholders' capital, ending balance at Dec. 31, 2022					464,526,130
Unitholders' capital, ending balance at Dec. 31, 2022	$ 463,751,910	$ 774,220	111,983,546		$ 576,509,676
Unitholders' capital, ending balance (in units) at Dec. 31, 2022	64,231,833	15,484,400			64,231,833
Increase (Decrease) in Unitholders' Capital
Common units issued for equity offering	$ 110,711,383				$ 110,711,383
Common units issued for equity offering (in units)	8,337,500
Conversion of Class B units to common units	$ 47,733	$ (316)	(47,733)		(316)
Conversion of Class B units to common units (in units)	6,323	(6,323)
Restricted units repurchased for tax withholding	$ (4,851,962)				(4,851,962)
Restricted units repurchased for tax withholding (in units)	(279,662)
Units issued for acquisition	$ 8,654,900	$ 268,461	83,383,956		92,307,317
Units issued for acquisition (in units)	557,302	5,369,218
Unit-based compensation	$ 13,111,522				13,111,522
Unit-based compensation (in units)	998,162
Distributions to unitholders	$ (120,372,624)		(31,551,122)		(151,923,746)
Distribution and accretion on Series A preferred units	(4,921,063)		(1,389,152)		(6,310,215)
Distribution on Class B units	(88,786)				(88,786)
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation	1,192,969		379,768		1,572,737
Change in ownership of consolidated subsidiaries, net	23,421,490		(23,421,490)		(23,421,490)
Net income	65,151,528		17,854,042		83,005,570
Unitholders' capital, ending balance at Dec. 31, 2023					556,851,365
Unitholders' capital, ending balance at Dec. 31, 2023	$ 555,809,000	$ 1,042,365	$ 157,191,815		$ 714,043,180
Unitholders' capital, ending balance (in units) at Dec. 31, 2023	73,851,458	20,847,295			73,851,458

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 83,005,570	$ 130,794,286	$ 42,437,874
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense	96,477,003	50,086,414	36,797,881
Impairment of oil and natural gas properties	18,220,173	0	0
Amortization of right-of-use assets	336,080	319,674	298,093
Amortization of loan origination costs	1,943,025	1,872,700	1,556,769
Loss on extinguishment of debt	480,244
Equity income in affiliate		(2,668,844)	(1,119,819)
Cash distribution from affiliate		3,770,651	1,015,559
Forfeiture of restricted units		(19,813)
Unit-based compensation	13,111,522	11,107,639	10,632,725
(Gain) loss on derivative instruments, net of settlements	(26,371,058)	(14,300,570)	20,343,783
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables	(12,026,760)	(11,846,567)	(17,594,389)
Accounts receivable and other current assets	1,863,376	(511,319)	(2,077,637)
Accounts payable	509,400	399,318	(77,716)
Other current liabilities	1,263,804	1,590,016	(463,828)
Operating lease liabilities	(348,668)	(324,913)	(306,814)
Net cash provided by operating activities	174,267,667	166,636,493	91,442,481
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment	(141,297)	(163,140)	(772,688)
Purchase of oil and natural gas properties	(490,665,514)	(141,297,776)	(55,300,252)
Proceeds from trust of variable interest entity	930,850
Cash distribution from affiliate		3,637,015	500,389
Net cash used in investing activities	(246,676,974)	(374,723,901)	(55,572,551)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of Series A preferred units, net of issuance costs	313,950,000
Proceeds from equity offering, net of issuance costs	110,711,383	116,119,417	57,522,440
Contributions from Class B unitholders	268,461	363,641
Redemption of Class B contributions on converted units	(316)	(470,000)	(158,410)
Redemption on Series A preferred units			(67,081,680)
Distribution to common unitholders	(120,372,624)	(107,402,294)	(47,309,785)
Distribution to OpCo unitholders	(31,551,122)	(19,323,523)	(21,534,575)
Distribution on Series A preferred units	(961,644)		(2,800,012)
Distribution on Class B units	(88,786)	(42,243)	(76,780)
Borrowings on long-term debt	201,084,089	199,200,000	136,565,769
Repayments on long-term debt	(139,900,000)	(183,300,000)	(91,000,000)
Payment of loan origination costs	(6,744,636)	(662,320)	(684,767)
Restricted units repurchased for tax withholding	(4,851,962)	(3,344,828)	(2,064,693)
Net cash provided by (used in) financing activities	78,375,409	226,061,562	(38,622,493)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,966,102	17,974,154	(2,752,563)
CASH AND CASH EQUIVALENTS, beginning of period	25,026,568	7,052,414	9,804,977
CASH AND CASH EQUIVALENTS, end of period	30,992,670	25,026,568	7,052,414
Supplemental cash flow information:
Cash paid for interest	23,727,572	11,207,530	7,538,814
Cash paid for taxes	2,281,000	3,082,245
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties	92,038,856	120,292,459
Noncash effect of Series A preferred unit redemption			14,893,784
Noncash deemed distribution to Series A preferred units	473,571		9,431,794
Distribution on Series A preferred units in accounts payable	4,875,000
Recognition of tenant improvement asset	125,000	125,001	447,917
Right-of-use assets obtained in exchange for operating lease liabilities			$ 19,636
Consolidated variable interest entities
Changes in operating assets and liabilities:
Interest earned on marketable securities in trust account	(3,508,691)	(3,721,145)
Other assets and liabilities	(687,353)	88,966
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for transaction costs	31,553
Cash received from investments held in trust	243,167,434
Investment in marketable securities		(236,900,000)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of underwriting commissions with equity offering of Kimbell Tiger Operating Company, net of adjustments		(2,661,288)
Proceeds from initial public offering of Kimbell Tiger Operating Company		227,585,000
Redemption of Kimbell Tiger Acquisition Corporation equity units	(243,167,434)
CASH AND CASH EQUIVALENTS, beginning of period	390,850
CASH AND CASH EQUIVALENTS, end of period		390,850
Non-cash investing and financing activities:
Reduction of deferred underwriting commission associated with redemption of Kimbell Tiger Acquisition Corporation equity units	$ (8,050,000)
Deferred underwriting commissions		$ 8,050,000

CONSOLIDATED STATEMENTS OF CA_2

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows
Cash and cash equivalents	$ 30,992,670	$ 25,026,568	$ 7,052,414
Consolidated variable interest entities
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows
Cash and cash equivalents		390,850
Non-Consolidated Variable Interest Entity Primary Beneficiary
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows
Cash and cash equivalents	$ 30,992,670	$ 24,635,718	$ 7,052,414

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2023
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” or “OpCo” 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. 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”) and all intercompany balances are eliminated in consolidation. A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows. Correction of Immaterial Errors Subsequent to the initial issuance of the consolidated financial statements for the year ended December 31, 2023, the Partnership identified an error in its application of accounting guidance related to the changes in ownership of OpCo. The Partnership previously accounted for the changes in ownership of OpCo (which occurred as a result of unit issuances by OpCo or the exchange by OpCo investors into common units) by reallocating the non-controlling interest associated with such changes at fair value. Under ASC 810-10, changes in ownership of a consolidated subsidiary that is less than wholly owned (such as OpCo) should accounted for by adjusting the carrying value of such non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the non-controlling interest is adjusted should be recognized in equity attributable to the parent. The Partnership has corrected these errors and determined that the related impact was not material to its previously issued financial statements. The Partnership has corrected these errors in the Consolidated Financial Statements for all prior periods presented herein. See Note 18, “Correction of Immaterial Errors”. Use of Estimates Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates. Segment Reporting The Partnership operates in a single reportable Global Conflicts In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas and is still active. These conflicts and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, the Partnership has not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, the Partnership will continue to monitor for events that could materially impact them.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2023
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 NGL 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, 2023 and 2022, 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 statements of operations within gain (loss) on commodity derivative instruments. Interest Rate Swaps The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted 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 were 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 Loan Origination Costs Certain direct costs associated with the Partnership’s secured 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, 2023, 2022 or 2021. 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, 2023, 2022 or 2021. 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 applicable to limited partners is computed utilizing the “if-converted” method, which is calculated by dividing limited partners’ interested in net income by the weighted average number of outstanding common units. The treasury-stock method is utilized to determine the dilutive effect, if any, of unvested common units granted under the Partnership’s long-term incentive plan (“LTIP”). 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. The non-controlling interest, which represents OpCo common unitholders’, as defined below, are not subject to federal income taxes. 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, 2023, 2022 and 2021. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2023, 2022 and 2021, 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, 2023, 2022 and 2021, the Partnership’s top Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. While the Partnership does not require the counterparties to its derivative contracts to post collateral, the Partnership does evaluate the credit standing of such counterparties as they deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. Non-controlling Interest Non-controlling interest in the accompanying consolidated financial statements represents OpCo common unitholders’, as defined below, ownership in the net assets of the Operating Company. When the OpCo common unitholders’ relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 10—Unitholders’ Equity and Partnership Distributions for further discussion. 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. The following table disaggregates the Partnership’s oil, natural gas, and NGL revenues for the following periods: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 2022 ​ 2021 Oil revenue ​ $ 183,150,517 ​ $ 130,811,485 ​ $ 87,151,724 Natural gas revenue ​ ​ 59,524,413 ​ ​ 122,632,983 ​ ​ 66,977,352 NGL revenue ​ ​ 24,909,855 ​ ​ 28,519,658 ​ ​ 20,958,945 Total Oil, natural gas and NGL revenues ​ $ 267,584,785 ​ $ 281,964,126 ​ $ 175,088,021 ​ 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. Consolidation The Partnership analyzes whether it has a variable interest in an entity and whether that entity is a variable interest entity (“VIE”) to determine whether it is required to consolidate those entities. The Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of all entities with respect to which the Partnership serves as the sponsor, general partner or managing member, and general partner entities not wholly owned by the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required. In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment. For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis. VIEs of which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations. Investments Held in Trust by Consolidated Variable Interest Entities Investments held in trust represent funds raised by TGR (as defined in Note 3), a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 3). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and presented on the balance sheets at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities were included in other income (expense)—interest earned on marketable securities in trust account on the accompanying consolidated statements of operations. The estimated fair values of investments held in the trust account were determined using quoted prices in an active market and therefore classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements. Redeemable Non-Controlling Interest Redeemable non-controlling interests represented the shares of Class A common stock of TGR par value $0.0001 per share (the “Class A common stock”) sold in the TGR IPO that were redeemable for cash by the public TGR shareholders that would have been concurrent with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests were initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. As of June 30, 2023, the shares had been redeemed in full. Recently Issued Accounting Pronouncements In March 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-01, “Leases (Topic 842): Common Control Arrangements.” This update requires that (i) entities determine whether a related party arrangement between entities under common control is a lease and (ii) that leasehold improvements have an amortization period consistent with the shorter of the remaining lease term and the useful life of the improvements, which is an approach that is largely consistent with legacy guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2023, including interim periods within that fiscal year. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 820): Improvements to Reportable Segment Disclosures.” The amendments in this update apply to all public entities that are required to report segment information in accordance with Topic 280, Segment Reporting. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. For entities other than public business entities, the amendments are effective for annual periods beginning after December 15, 2025. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

ACQUISITIONS, JOINT VENTURES AN

ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY	12 Months Ended
	Dec. 31, 2023
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 2023 Activity On September 13, 2023, the Partnership completed the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) in a cash transaction valued at approximately $455.0 million. The Partnership funded the cash transaction with borrowings under its secured revolving credit facility and net proceeds from the Preferred Unit Transaction (as defined in Note 9—Preferred Units). The adjusted purchase price of the LongPoint Acquisition includes the total cash consideration of $455.0 million, transactional costs of $7.4 million and less $16.6 million of post-effective net oil, natural gas and NGL revenues earned prior to the closing date. The LongPoint Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $198.2 million to proved properties and $247.6 million to unevaluated properties. On May 17, 2023, the Partnership completed the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”). The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 OpCo Common Units and an equal number of Class B units representing limited partnership interests in the Partnership (“Class B units”) and (b) 557,302 common units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas. The MB Minerals Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $60.8 million to proved properties and $74.9 million to unevaluated properties. 2022 Activity On December 15, 2022, Hatch Royalty LLC (the “Hatch Acquisition”). Class B 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”) Both 2021 acquisitions were accounted for as asset acquisitions and the allocation of the purchase price was $55.3 million to proved properties. 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 was 49.3%. During the year ended December 31, 2022, the Joint Venture completed the sale of its royalty, mineral and overriding interests and similar non-cost bearing interests in oil and gas properties for a total purchase price of $15.0 million. Net proceeds distributed to the Partnership were $6.5 million during the year ended December 31, 2022, the majority of which was used to repay debt on the Partnership’s secured revolving credit facility. On November 1, 2022, the Joint Venture was dissolved. Special Purpose Acquisition Company On January 29, 2021, the Partnership’s recently dissolved special purpose acquisition company and subsidiary, Kimbell Tiger Acquisition Corporation (“TGR”), filed a registration statement on Form S-1 with the United States Securities and Exchange Commission (“SEC”). TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”), which was a subsidiary of the Partnership, and was created to assist TGR in sourcing, analyzing and consummating acquisition opportunities for that initial business combination. TGR Sponsor and TGR were consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021. On February 8, 2022, TGR consummated its $230.0 million initial public offering (the “TGR IPO”). Under the terms of TGR’s governing documents, TGR had until May 8, 2023 to complete a business combination, subject to TGR Sponsor’s option to extend such deadline by three months up to two times. On May 22, 2023, as a result of TGR’s inability to consummate an initial business combination on or prior to May 8, 2023, and pursuant to the terms of its organizational documents, TGR redeemed all of its outstanding shares of Class A common stock included as part of the units issued in its initial public offering. The Class A common stock was redeemed on June 22, 2023 and the Partnership completed the dissolution and deconsolidation of TGR (along with TGR Sponsor) on June 30, 2023 in accordance with the terms of its organizational documents. The net non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying consolidated balance sheet of as of December 31, 2023 and treated as accretion of redeemable non-controlling interest in TGR in the accompanying consolidated statements of changes in unitholders’ equity for the year ended December 31, 2023

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2023
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, 2023, 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’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 scheduled trading day of the first nearby month futures contract corresponding to the relevant 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, ​ ​ 2023 ​ 2022 ​ 2021 Beginning fair value of derivative instruments ​ $ (12,324,076) ​ $ (26,624,646) ​ $ (6,280,863) Gain (loss) on commodity derivative instruments, net ​ ​ 20,888,972 ​ ​ (32,240,915) ​ ​ (41,240,942) Net cash paid on settlements of derivative instruments ​ ​ 5,482,086 ​ ​ 46,541,485 ​ ​ 20,897,159 Ending fair value of derivative instruments ​ $ 14,046,982 ​ $ (12,324,076) ​ $ (26,624,646) ​ 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 ​ 2023 ​ 2022 Assets: ​ ​ ​ ​ ​ ​ ​ ​ Current assets ​ Derivative assets ​ $ 11,427,735 ​ $ — Long-term assets ​ Derivative assets ​ ​ 2,888,051 ​ ​ 754,786 Liabilities: ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ Derivative liabilities ​ ​ (208,710) ​ ​ (12,646,720) Long-term liabilities ​ Derivative liabilities ​ ​ (60,094) ​ ​ (432,142) ​ ​ ​ ​ $ 14,046,982 ​ $ (12,324,076) ​ At December 31, 2023, 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 2024 - December 2024 ​ 568,926 ​ $ 79.04 ​ $ 69.30 ​ $ 85.34 January 2025 - December 2025 ​ 563,526 ​ $ 70.36 ​ $ 64.35 ​ $ 77.01 Natural Gas Price Swaps ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Notional ​ Weighted Average ​ Range (per MMBtu) ​ ​ Volumes (MMBtu) ​ Fixed Price (per MMBtu) ​ Low ​ High January 2024 - December 2024 ​ 5,285,182 ​ $ 3.97 ​ $ 3.06 ​ $ 4.48 January 2025 - December 2025 ​ 5,153,291 ​ $ 3.81 ​ $ 3.50 ​ $ 4.37 ​

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2023
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, 2023 and 2022 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, 2023 and 2022. The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy. The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. The following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements Using ​ ​ ​ ​ ​ ​ ​ ​ Level 1 ​ Level 2 ​ Level 3 ​ Effect of Counterparty Netting ​ Total December 31, 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ 14,315,786 ​ $ — ​ $ — ​ $ 14,315,786 Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ (268,804) ​ $ — ​ $ — ​ $ (268,804) December 31, 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ 754,786 ​ $ — ​ $ — ​ $ 754,786 Assets of consolidated variable interest entities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Investments held in trust ​ $ 240,621,146 ​ $ — ​ $ — ​ $ — ​ $ 240,621,146 Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ (13,078,862) ​ $ — ​ $ — ​ $ (13,078,862) ​

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	12 Months Ended
	Dec. 31, 2023
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, ​ ​ 2023 ​ 2022 Oil and natural gas properties ​ ​ ​ ​ ​ ​ Proved properties ​ $ 1,825,977,244 ​ $ 1,258,290,375 Unevaluated properties ​ ​ 222,712,844 ​ ​ 207,695,343 Less: accumulated depreciation, depletion and impairment ​ ​ (827,033,944) ​ ​ (712,716,951) Total oil and natural gas properties ​ $ 1,221,656,144 ​ $ 753,268,767 ​ The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The Partnership assesses all unevaluated properties on a 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 developed 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. As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $18.2 million during the year ended December 31, 2023. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. The Partnership did not record an impairment on its oil and natural gas properties for the years ended December 31, 2022 and 2021.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2023
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, 2023 is 5.43 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, 2023. 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. The total operating lease expense recorded for the years ended December 31, 2023, 2022 and 2021 was $0.6 million, $0.5 million and $0.4 million, respectively. Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations. Maturities of lease liabilities as of December 31, 2023 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ 2024 ​ 2025 ​ 2026 ​ 2027 ​ 2028 ​ Thereafter Operating leases ​ $ 2,712,673 ​ $ 488,725 ​ $ 497,033 ​ $ 507,648 ​ $ 511,917 ​ $ 496,785 ​ $ 210,565 Less: Imputed Interest ​ (476,273) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ $ 2,236,400 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2023
LONG-TERM DEBT.
LONG-TERM DEBT	NOTE 8—LONG-TERM DEBT On June 13, 2023, the Partnership entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022). The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $750.0 million with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million, and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027. A&R Credit Agreement Partnership’s existing credit agreement &R Credit Agreement On July 24, 2023, the Partnership entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amended the A&R Credit Agreement to, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million, and (ii) permit the Partnership to issue certain preferred equity interests. On December 8, 2023, in connection with the November 1, 2023 redetermination, the Partnership Amendment No. 2 ( The amendment amends the A&R Credit Agreement to The secured bears interest at a rate equal to, at the Partnership’s election, either (a) the Secured Overnight Financing Rate (as defined in the A&R Credit Agreement) plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization. The secured is guaranteed by certain of the Partnership’s material subsidiaries and is collateralized by substantially all assets, including the oil and natural gas properties of such subsidiaries, including mortgages on at least 75% of the PV-9 of the proved reserves constituting borrowing base properties as set forth on the Partnership’s most recent reserve report. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year by the Lenders, with one interim unscheduled redetermination available to each of the Partnership and a group of certain Lenders between scheduled redeterminations during each calendar year. The next scheduled redetermination will be on or around May 1, 2024. Customary borrowing base reductions and mandatory prepayments are required under the A&R Credit Agreement in connection with certain sales of certain types of borrowing base properties, sales of equity interests in guarantor subsidiaries owning such properties, certain debt issuances or certain types of swap terminations. In addition, Cash Balance (as defined in the First Amendment) above $50.0 million is required to be applied weekly to prepay loans (without a commitment reduction) if not otherwise reduced to zero in a manner permitted by the A&R Credit Agreement. The Partnership is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the . The Partnership is also required to pay customary letter of credit and fronting fees. The A&R Credit Agreement requires the Partnership to maintain as of the last day of each fiscal quarter: (i) a Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) of not more than and (ii) a ratio of current assets to current liabilities of not less than . The A&R Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants. These covenants are subject to a number of limitations and exceptions. Additionally, the A&R Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Partnership does not comply with the financial and other covenants in the A&R Credit Agreement, the Lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the A&R Credit Agreement and any outstanding unfunded commitments may be terminated. During the year ended December 31, 2023, the Partnership borrowed an additional $201.1 million under the secured revolving credit facility and repaid approximately $139.9 million of the outstanding borrowings. As of December 31, 2023, the Partnership’s outstanding balance was $294.2 million and there were no outstanding letters of credit under the secured revolving credit facility. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2023. As of December 31, 2023, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of 3.25% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.25%. For the year ended December 31, 2023, the weighted average interest rate on the Partnership’s outstanding borrowings was 8.62%.

PREFERRED UNITS

PREFERRED UNITS	12 Months Ended
	Dec. 31, 2023
PREFERRED UNITS
PREFERRED UNITS	NOTE 9—PREFERRED UNITS On August 2, 2023, the Partnership entered into a Series A preferred unit purchase agreement with certain funds managed by affiliates of Apollo (NYSE: APO) (collectively, the “Series A Purchasers”) to issue and sell up to 400,000 Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”). On September 13, 2023, in connection with the closing of the LongPoint Acquisition, the Partnership completed the private placement of 325,000 Series A preferred units to the Series A Purchasers for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $325.0 million (the “Preferred Unit Transaction”). The Partnership used the net proceeds from the Preferred Unit Transaction to purchase 325,000 preferred units of the Operating Company (“OpCo preferred units”). The Operating Company in turn used the net proceeds to fund a portion of the LongPoint Acquisition. The Series A preferred units rank senior to the Partnership’s common units with respect to distribution rights and rights upon liquidation. 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 6.0% per annum plus accrued and unpaid distributions. The Partnership has the right, in any four non-consecutive quarters, to elect not to pay such quarterly distribution in cash and instead have the unpaid distribution amount added to the liquidation preference at the rate of 10.0% per annum. If the Partnership makes such an election in consecutive quarters or if the Partnership fails to pay in full, in cash and when due, any distribution owed to the Series A preferred units or otherwise materially breaches its obligations to the holders of the Series A preferred units, the distribution rate will increase to 20.0% per annum until the accumulated distributions are paid in full in cash, or any such material breach is cured, as applicable. Each holder of Series A preferred units has the right to share in any special distributions by the Partnership of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. The Partnership cannot declare or make any distributions, redemptions, or repurchases on any junior securities, including any of their common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions. Beginning with the earlier of (i) the second anniversary of the original issuance date and (ii) immediately prior to a liquidation of the Partnership, the Series A Purchasers may, at any time (but not more often than once per quarter), elect to convert all or any portion of their Series A preferred units into a number of common units determined by multiplying the number of Series A preferred units to be converted by the then-applicable conversion rate, provided that (a) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ remaining Series A preferred units and (b) the closing price of the common units is at least 130% of the conversion price of $15.07, subject to certain anti-dilution adjustments (the “Conversion Price”) for 20 trading days during the 30-trading day period immediately preceding the conversion notice. At any time on or after the second anniversary of the original issuance date, the Partnership will have the option to convert all or any portion of the Series A preferred units into a number of common units determined by the then-applicable conversion rate, provided that (i) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ Series A preferred units, (ii) the common units are listed for, or admitted to, trading on a national securities exchange, (iii) the closing price of the common units is at least 160% of the Conversion Price for 20 trading days during the 30-trading day period immediately preceding the conversion notice and (iv) the Partnership has an effective registration statement on file with the SEC covering resales of the underlying common units to be received by the holders of Series A preferred units upon such conversion. The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years from the effective date of the Series A preferred unit purchase agreement, August 2, 2023. The Series A preferred units may be redeemed by the Partnership at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A p referred unit and (iii) the Series A issue price plus accrued and unpaid distributions. For purposes of the , “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of , a 12.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the original issuance date and prior to the sixth anniversary of the original issuance date, a 13.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the original issuance date, a 14.0% internal rate of return with respect to the Series A preferred units. 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 fifth anniversary of the original issuance date, board appointment rights beginning on the sixth anniversary of the original issuance date, and in the case of events of default with respect to the Series A preferred units, the right to appoint two members of the board beginning on the seventh anniversary of the original issuance date. The terms of the Series A preferred units contain covenants preventing the Partnership from taking certain actions without the approval of the holders of 66 2 / 3 ​

UNITHOLDERS' EQUITY AND PARTNER

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS	12 Months Ended
	Dec. 31, 2023
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. As of December 31, 2023, the Partnership had a total of 73,851,458 common units issued and outstanding On August 7, 2023, the Partnership completed an underwritten public offering of 8,337,500 common units for net proceeds of approximately $110.7 million (the “2023 Equity Offering”). The Partnership used the net proceeds from the 2023 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $90.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. The Operating Company used the remainder of the net proceeds of the 2023 Equity Offering for general corporate purposes. In November 2022, the Partnership completed an underwritten public offering of 6,900,000 common units for net proceeds of approximately $116.1 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the 2022 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $116.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. 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, 2022 ​ 64,231,833 Common units issued under the A&R LTIP (1) ​ 998,162 Restricted units repurchased for tax withholding ​ (279,662) Common unit issued for acquisition ​ 557,302 Common units issued for equity offering ​ 8,337,500 Conversion of Class B units ​ 6,323 Balance at December 31, 2023 ​ 73,851,458 (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 “A&R LTIP”) on February 21, 2023. 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 2023 ​ $ 0.35 ​ May 3, 2023 ​ May 15, 2023 ​ May 22, 2023 Q2 2023 ​ $ 0.39 ​ August 2, 2023 ​ August 14, 2023 ​ August 21, 2023 Q3 2023 ​ $ 0.51 ​ November 2, 2023 ​ November 13, 2023 ​ November 20, 2023 Q4 2023 ​ $ 0.43 ​ February 21, 2024 ​ March 13, 2024 ​ March 20, 2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Q1 2022 ​ $ 0.47 ​ April 22, 2022 ​ May 2, 2022 ​ May 9, 2022 Q2 2022 ​ $ 0.55 ​ August 3, 2022 ​ August 15, 2022 ​ August 22, 2022 Q3 2022 ​ $ 0.49 ​ November 3, 2022 ​ November 14, 2022 ​ November 21, 2022 Q4 2022 ​ $ 0.48 ​ February 23, 2023 ​ March 9, 2023 ​ March 16, 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ The following table summarizes the changes in the number of the Partnership’s Class B units: ​ ​ ​ ​ ​ ​ Class B Units Balance at December 31, 2022 ​ 15,484,400 Class B units issued for acquisition ​ 5,369,218 Conversion of Class B units ​ (6,323) Balance at December 31, 2023 ​ 20,847,295 ​ For each Class B unit issued, five cents have 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 PER COMMON UNIT

EARNINGS PER COMMON UNIT	12 Months Ended
	Dec. 31, 2023
EARNINGS PER COMMON UNIT
EARNINGS PER COMMON UNIT	NOTE 11—EARNINGS PER COMMON UNIT Basic earnings per common unit is calculated by dividing net income attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 12) for its employees, directors and consultants and potential conversion of Series A preferred units and Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Series A preferred units and 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 A&R 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, ​ ​ 2023 ​ 2022 ​ 2021 Net income attributable to common units of Kimbell Royalty Partners, LP ​ $ 60,141,679 ​ $ 111,929,491 ​ $ 22,615,021 Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions ​ ​ 1,572,737 ​ ​ (17,412,732) ​ ​ — Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions ​ ​ 61,714,416 ​ ​ 94,516,759 ​ ​ 22,615,021 Distribution and accretion on Series A preferred units ​ ​ 6,310,215 ​ ​ — ​ ​ ​ Net income attributable to non-controlling interests in OpCo and distribution on Class B units ​ ​ 16,553,676 ​ ​ 18,864,795 ​ ​ 8,496,104 Diluted net income attributable to common units of Kimbell Royalty Partners, LP ​ $ 84,578,307 ​ $ 113,381,554 ​ $ 31,111,125 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of common units outstanding: ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ ​ 66,595,273 ​ ​ 54,112,595 ​ ​ 40,400,907 Effect of dilutive securities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Series A preferred units ​ ​ 6,499,350 ​ ​ — ​ ​ — Class B units ​ ​ 18,851,387 ​ ​ 10,819,266 ​ ​ 18,839,607 Restricted units ​ ​ 1,111,721 ​ ​ 905,156 ​ ​ 1,717,310 Diluted ​ ​ 93,057,731 ​ ​ 65,837,017 ​ ​ 60,957,824 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income per unit attributable to common units of Kimbell Royalty Partners, LP ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ $ 0.93 ​ $ 1.75 ​ $ 0.56 Diluted ​ $ 0.91 ​ $ 1.72 ​ $ 0.51 ​ The calculation of diluted net income per share for the year ended December 31, 2023 includes the conversion of Series A preferred units to common units and Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method. The calculation of diluted net income per share for the years ended December 31, 2022 and 2021 includes the conversion of all Class B units to common units calculated using the “if-converted” method and unvested restricted units calculated using the treasury stock method.

UNIT-BASED COMPENSATION

UNIT-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2023
UNIT-BASED COMPENSATION
UNIT-BASED COMPENSATION	NOTE 12—UNIT-BASED COMPENSATION On May 18, 2022, the Partnership held a special meeting of unitholders of the Partnership (the “Special Meeting”), at which the Partnership’s unitholders voted to approve the Amended and Restated Kimbell Royalty GP, LLC 2017 Long- Term Incentive Plan (the “A&R LTIP”), 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, 2022 ​ 1,897,192 ​ $ 13.553 1.517 years Awarded ​ 998,162 ​ ​ 15.020 ​ — Vested ​ (943,924) ​ ​ 12.602 ​ — Unvested at December 31, 2023 ​ 1,951,430 ​ $ 14.763 1.525 years ​

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2023
INCOME TAXES
INCOME TAXES	NOTE 13—INCOME TAXES The Partnership’s provision for income taxes is based on the estimated annual effective tax rate. The Partnership incurred $3.8 million and $2.7 million of income taxes for the years ended December 31, 2023 and 2022, respectively, and a de minimis amount of income taxes during the year ended December 31, 2021. The Partnership has filed all tax returns to date that are currently due. The Partnership’s effective income tax rate was 4.34% for the year ended December 31, 2023. The Partnership earned income before taxes, as calculated under GAAP, for the current year and is recording a current income tax expense of $3.8 million primarily related to income that was not sheltered due to depletion and other non-cash deductions. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Current ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ $ 2,469,584 ​ $ 2,412,702 ​ $ 69,067 State ​ ​ 1,296,718 ​ ​ 326,000 ​ ​ 5,033 Total Current ​ ​ 3,766,302 ​ ​ 2,738,702 ​ ​ 74,100 Deferred ​ ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ ​ — ​ ​ — ​ ​ — State ​ ​ — ​ ​ — ​ ​ — Total Deferred ​ ​ — ​ ​ — ​ ​ — Provision for income taxes ​ $ 3,766,302 ​ $ 2,738,702 ​ $ 74,100 ​ The Partnership’s income tax expense differs from the amount derived by applying the statutory federal rate to pre-tax income principally due the effect of the following items: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Net income before taxes ​ $ 86,771,872 ​ ​ $ 133,532,988 ​ ​ $ 42,511,974 ​ Statutory rate ​ ​ 21 % ​ ​ 21 % ​ ​ 21 % Income tax provision computed at statutory rate ​ ​ 18,222,093 ​ ​ ​ 28,041,927 ​ ​ ​ 8,927,515 ​ Reconciling items: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ State income taxes ​ ​ 1,393,149 ​ ​ ​ 326,000 ​ ​ ​ 5,033 ​ Non-controlling interest ​ ​ (3,518,924) ​ ​ ​ (3,988,366) ​ ​ ​ (1,788,347) ​ Income at OpCo ​ ​ (14,703,170) ​ ​ ​ (24,053,561) ​ ​ ​ (7,139,168) ​ Change in valuation allowance - federal ​ ​ 2,860,951 ​ ​ ​ 2,202,314 ​ ​ ​ (363,132) ​ Change in valuation allowance - state ​ ​ (96,431) ​ ​ ​ (1,307,605) ​ ​ ​ (40,626) ​ Other, net ​ ​ (391,366) ​ ​ ​ 1,517,993 ​ ​ ​ 472,825 ​ Provision for income taxes ​ $ 3,766,302 ​ ​ $ 2,738,702 ​ ​ $ 74,100 ​ ​ 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, ​ ​ 2023 ​ 2022 ​ 2021 Deferred tax asset ​ ​ ​ ​ ​ ​ Outside basis in OpCo ​ $ 22,624,765 ​ $ 18,494,572 ​ $ 6,641,452 Federal tax loss carryforwards ​ ​ — ​ ​ 2,645,475 ​ ​ 12,296,282 State tax loss carryforwards ​ ​ 385,926 ​ ​ 482,356 ​ ​ 1,789,961 Business interest deduction limitation ​ ​ 1,376,234 ​ ​ — ​ ​ — Deferred tax asset ​ ​ 24,386,925 ​ ​ 21,622,403 ​ ​ 20,727,695 Valuation allowance ​ ​ (24,386,925) ​ ​ (21,622,403) ​ ​ (20,727,695) Net deferred tax asset ​ $ — ​ $ — ​ $ — ​ The tax years ended December 31, 2020 through 2023 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 $24.4 million on the deferred tax assets. As of December 31, 2023, the Partnership has not

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2023
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	NOTE 14—RELATED PARTY TRANSACTIONS The Partnership currently has a management services agreement with Kimbell Operating, which has separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), K3 Royalties, LLC (“K3 Royalties”), 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, 2023, no monthly services fee was paid to BJF Royalties. During the year ended December 31, 2023, the Partnership made payments to K3 Royalties in the amount of $120,000. 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 $26,500 for the year ended December 31, 2023, for the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $602,600 for the year ended December 31, 2023. The Partnership received $180,626 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the year ended December 31, 2023. Commencing on the date of the TGR IPO, TGR agreed to pay the Partnership a total of $25,000 per quarter for office space utilities, secretarial support and administrative services provided to members of the management team. During the year ended December 31, 2023, TGR incurred $50,000 as part of this service agreement. Such fees were eliminated in consolidation.

ADMINISTRATIVE SERVICES

ADMINISTRATIVE SERVICES	12 Months Ended
	Dec. 31, 2023
ADMINISTRATIVE SERVICES
ADMINISTRATIVE SERVICES	NOTE 15—ADMINISTRATIVE SERVICES On September 13, 2023, in connection with the LongPoint Acquisition and pursuant to the terms of the securities purchase agreement, a transition services agreement (the “Transition Services Agreement”) by and between the Operating Company and FourPoint Energy, LLC (“FourPoint”), the former manager of the acquired assets, became effective. Pursuant to the Transition Services Agreement, FourPoint provided certain administrative services and accounting assistance on a transitional basis for a monthly service fee of approximately $250,000 for the four-month period ending January 13, 2024, at which the Transition Services Agreement was terminated by the Partnership. During the year ended December 31, 2023, the Partnership paid $0.9 million in Transition Services Agreement costs.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2023
COMMITMENTS AND CONTINGENCIES.
COMMITMENTS AND CONTINGENCIES	NOTE 16—COMMITMENTS AND CONTINGENCIES 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, 2023.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2023
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 17—SUBSEQUENT EVENTS The Partnership has evaluated events that occurred subsequent to December 31, 2023 in the preparation of its consolidated financial statements. Distributions On February 21, 2024, the Board of Directors declared a quarterly cash distribution of $0.43 per common unit and $0.453897 per OpCo common unit for the quarter ended December 31, 2023. The Partnership intends to pay this distribution on March 20, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on March 13, 2024. As to the Partnership, $0.023897 of the OpCo common unit distribution corresponds to a tax payment made by the Partnership in the fourth quarter of 2023. Under the limited liability company agreement of the Operating Company, the Partnership is not reimbursed by the Operating Company for federal income taxes paid by the Partnership. The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $4.9 million for the quarter ended December 31, 2023. We intend to pay the distribution subsequent to March 13, 2024 and prior to the distribution on the common units and OpCo common units. Executive Bonus and LTIP Issuance On February 19, 2024, the Conflicts and Compensation Committee of the Board of Directors approved short-term incentive cash bonuses for executive officers of approximately $2.5 million and the issuance of 1,087,502 restricted units to its employees and directors.

CORRECTION OF IMMATERIAL ERRORS

CORRECTION OF IMMATERIAL ERRORS	12 Months Ended
	Dec. 31, 2023
CORRECTION OF IMMATERIAL ERRORS
CORRECTION OF IMMATERIAL ERRORS	NOTE 18—CORRECTION OF IMMATERIAL ERRORS The Partnership has identified an error in its application of accounting guidance related to the changes in ownership of OpCo. The Partnership previously accounted for changes in ownership of OpCo by reallocating the non-controlling interest associated with such changes at fair value. Under ASC 810-10, changes in ownership of a consolidated subsidiary that is less than wholly owned (such as OpCo) should be accounted for by adjusting the carrying value of such non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the noncontrolling interest is adjusted should be recognized in equity attributable to the parent. The Partnership evaluated the impact of this error on the previously issued financial statements and determined that it was not material to any periods. The error (i) resulted only in a reclass of amounts between components in unitholders’ equity (specifically, from Common Units to Non-Controlling Interest in OpCo) and (ii) did not have any impact on the Total Unitholders’ Equity amount in the Partnership’s consolidated balance sheets, the Total amount in the Partnership’s consolidated statement of changes in unitholders’ equity or any other portion of the Partnership’s financial statements. Moreover, the error had no impact on items in the Partnership’s consolidated statement of operations or statement of cash flows, including any information related to revenues, net income, net income attributable to common units, earnings per unit and other items. Further, the error did not have any impact on compliance with its material financial covenants under debt instruments or other contractual arrangements. The Partnership has adjusted its consolidated balance sheet at December 31, 2023 and 2022 and its consolidated statement of changes in unitholders’ equity for the years ended December 31, 2023, 2022 and 2021. The effects of the adjustments on the individual line items within the Partnership’s consolidated balance sheets and consolidated statement of changes in unitholders’ equity for the periods indicated are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ ​ As Reported ​ Adjustments ​ As Adjusted Common units ​ $ 328,717,841 ​ $ (75,597,839) ​ $ 253,120,002 Class B units ​ ​ 880,579 ​ ​ — ​ ​ 880,579 Non-controlling interest in OpCo ​ ​ 19,251,361 ​ ​ 75,597,839 ​ ​ 94,849,200 Total unitholders' equity ​ $ 348,849,781 ​ $ — ​ $ 348,849,781 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 ​ ​ As Reported ​ Adjustments ​ As Adjusted Common units ​ $ 601,841,776 ​ $ (138,089,866) ​ $ 463,751,910 Class B units ​ ​ 774,220 ​ ​ — ​ ​ 774,220 Non-controlling interest in OpCo ​ ​ (26,106,320) ​ ​ 138,089,866 ​ ​ 111,983,546 Total unitholders' equity ​ $ 576,509,676 ​ $ — ​ $ 576,509,676 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2023 ​ ​ As Reported ​ Adjustments ​ As Adjusted Common units ​ $ 670,530,748 ​ $ (114,721,748) ​ $ 555,809,000 Class B units ​ ​ 1,042,365 ​ ​ — ​ ​ 1,042,365 Non-controlling interest in OpCo ​ ​ 42,470,067 ​ ​ 114,721,748 ​ ​ 157,191,815 Total unitholders' equity ​ $ 714,043,180 ​ $ — ​ $ 714,043,180 ​ Change in Ownership of Consolidated Subsidiaries In addition to the error noted above related to the changes in ownership of OpCo, the Partnership added a new line item to its consolidated statement of changes in unitholders’ equity “Changes in ownership of consolidated subsidiaries, net.” This adjustment is included in the adjustment balances noted above. Non-controlling interest in the accompanying consolidated financial statements represents the non-controlling interest in the net assets of the Operating Company. The Partnership’s relative ownership interest in OpCo can change due to the Partnership’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, conversion of Class B to common units, repurchases of common units and distribution rights paid on the Partnership’s units. These changes in ownership percentage result in adjustments to non-controlling interest and common unitholders' equity. The following table summarizes the changes in common unitholders' equity due to changes in ownership interest during the period: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Net income attributable to the Partnership ​ $ 65,151,528 ​ $ 111,971,734 ​ $ 30,647,893 Changes in ownership of consolidated subsidiaries, net ​ ​ 23,421,490 ​ ​ 49,056,142 ​ ​ (12,295,407) Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest ​ $ 88,573,018 ​ $ 161,027,876 ​ ​ 18,352,486 ​

SUPPLEMENTAL OIL AND GAS RESERV

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2023
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)	NOTE 19—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, ​ 2023 ​ 2022 Oil, natural gas and NGL interests ​ ​ ​ ​ ​ ​ Proved properties ​ $ 1,825,977,244 ​ $ 1,258,290,375 Unevaluated properties ​ ​ 222,712,844 ​ ​ 207,695,343 Total oil, natural gas and NGL interests ​ 2,048,690,088 ​ 1,465,985,718 Accumulated depreciation, depletion, accretion and impairment ​ (827,033,944) ​ (712,716,951) Net oil, natural gas and NGL interests capitalized ​ $ 1,221,656,144 ​ $ 753,268,767 ​ 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, ​ ​ 2023 ​ 2022 ​ 2021 Acquisition costs ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved properties ​ $ 260,145,370 ​ $ 56,848,235 ​ $ 55,300,252 Unevaluated properties ​ ​ 322,559,000 ​ ​ 204,742,000 ​ ​ — Total ​ 582,704,370 ​ 261,590,235 ​ 55,300,252 Development costs ​ ​ ​ Proved properties ​ — ​ — ​ — Total ​ — ​ — ​ — Total costs incurred on oil, natural gas and NGL activities ​ $ 582,704,370 ​ $ 261,590,235 ​ $ 55,300,252 ​ 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, ​ ​ 2023 ​ 2022 ​ 2021 Oil, natural gas and NGL revenues ​ $ 267,584,785 ​ $ 281,964,126 ​ $ 175,088,021 Lease bonus and other income ​ ​ 5,594,855 ​ ​ 3,073,609 ​ ​ 3,319,104 Production and ad valorem taxes ​ (20,326,477) ​ (16,238,814) ​ (10,480,481) Depreciation and depletion expense ​ (96,477,003) ​ (50,086,414) ​ (36,797,881) Impairment of oil and natural gas properties ​ (18,220,173) ​ — ​ — Marketing and other deductions ​ (12,564,619) ​ (13,383,074) ​ (12,048,643) Results of operations from oil, natural gas and NGLs ​ $ 125,591,368 ​ $ 205,329,433 ​ $ 119,080,120 ​ 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. The estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2023, 2022 and 2021. 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. 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, 2021 ​ 12,294 ​ 144,233 ​ 6,085 ​ 42,418 Revisions of previous estimates (1) ​ 251 ​ 24,079 ​ 780 ​ 5,044 Purchase of minerals in place (2) ​ 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 Revisions of previous estimates (1) ​ (58) ​ 17,119 ​ 759 ​ 3,554 Purchase of minerals in place (3) ​ 1,328 ​ 5,726 ​ 707 ​ 2,989 Production ​ (1,426) ​ (20,311) ​ (747) ​ (5,558) Net proved reserves at December 31, 2022 ​ 12,355 ​ 160,298 ​ 7,388 ​ 46,459 Revisions of previous estimates (1) ​ 3,273 ​ 26,068 ​ 814 ​ 8,432 Purchase of minerals in place (4) ​ 6,565 ​ 41,560 ​ 4,400 ​ 17,892 Production ​ (2,393) ​ (23,384) ​ (1,083) ​ (7,374) Net proved reserves at December 31, 2023 ​ 19,800 ​ 204,542 ​ 11,519 ​ 65,409 ​ ​ ​ ​ ​ ​ ​ ​ ​ Net proved developed reserves ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ 12,511 ​ 157,764 ​ 6,669 ​ 45,474 December 31, 2022 ​ 12,355 ​ 160,298 ​ 7,388 ​ 46,459 December 31, 2023 ​ 19,800 ​ 204,542 ​ 11,519 ​ 65,409 (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 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. (3) Includes the acquisition of mineral and royalty interests for a total of $56.8 million, primarily consisting of mineral and royalty interests in the Permian Basin. (4) Includes the acquisition of mineral and royalty interests, primarily consisting of mineral and royalty interests in the Permian Basin and Mid-Continent. 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, ​ 2023 ​ 2022 ​ 2021 Future cash inflows ​ $ 2,226,313 ​ $ 2,253,273 ​ $ 1,335,917 Future production costs ​ ​ (164,848) ​ ​ (161,676) ​ ​ (100,947) Future state margin taxes ​ ​ (49,144) ​ ​ (76,322) ​ ​ (42,965) Future net cash flows ​ ​ 2,012,321 ​ ​ 2,015,275 ​ ​ 1,192,005 Less 10% annual discount to reflect timing of cash flows ​ ​ (1,037,192) ​ ​ (1,110,980) ​ ​ (665,390) Standard measure of discounted future net cash flows ​ $ 975,129 ​ $ 904,295 ​ $ 526,615 ​ 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 2023, 2022 and 2021 were $78.22, $93.67 and $66.56 per barrel for crude oil and $2.64, $6.36 and $3.60 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, ​ ​ 2023 ​ 2022 ​ 2021 Standardized measure - beginning of year ​ $ 904,295 ​ $ 526,615 ​ $ 284,996 Sales, net of production costs ​ ​ (236,953) ​ ​ (252,597) ​ ​ (152,751) Net changes of prices and production costs related to future production ​ ​ (302,599) ​ ​ 365,427 ​ ​ 225,868 Revisions of previous quantity estimates, net of related costs ​ ​ 128,727 ​ ​ 71,776 ​ ​ 60,517 Net changes in state margin taxes ​ ​ 10,433 ​ ​ (15,266) ​ ​ (8,665) Accretion of discount ​ ​ 78,425 ​ ​ 44,280 ​ ​ 25,743 Purchases of reserves in place ​ ​ 435,230 ​ ​ 77,719 ​ ​ 40,545 Timing differences and other ​ ​ (42,429) ​ ​ 86,341 ​ ​ 50,362 Standardized measure - end of year ​ $ 975,129 ​ $ 904,295 ​ $ 526,615 ​

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2023
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”) and all intercompany balances are eliminated in consolidation. A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.
Correction of Immaterial Errors	Correction of Immaterial Errors Subsequent to the initial issuance of the consolidated financial statements for the year ended December 31, 2023, the Partnership identified an error in its application of accounting guidance related to the changes in ownership of OpCo. The Partnership previously accounted for the changes in ownership of OpCo (which occurred as a result of unit issuances by OpCo or the exchange by OpCo investors into common units) by reallocating the non-controlling interest associated with such changes at fair value. Under ASC 810-10, changes in ownership of a consolidated subsidiary that is less than wholly owned (such as OpCo) should accounted for by adjusting the carrying value of such non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the non-controlling interest is adjusted should be recognized in equity attributable to the parent. The Partnership has corrected these errors and determined that the related impact was not material to its previously issued financial statements. The Partnership has corrected these errors in the Consolidated Financial Statements for all prior periods presented herein. See Note 18, “Correction of Immaterial Errors”.
Use of Estimates	Use of Estimates Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates. 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.
Segment Reporting	Segment Reporting The Partnership operates in a single reportable
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 NGL Receivables	Oil, Natural Gas and NGL 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, 2023 and 2022, 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 statements of operations within gain (loss) on commodity derivative instruments. Interest Rate Swaps The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted 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 were 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
Loan Origination Costs	Loan Origination Costs Certain direct costs associated with the Partnership’s secured
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, 2023, 2022 or 2021. 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, 2023, 2022 or 2021.
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 ​ Earnings per unit applicable to limited partners is computed utilizing the “if-converted” method, which is calculated by dividing limited partners’ interested in net income by the weighted average number of outstanding common units. The treasury-stock method is utilized to determine the dilutive effect, if any, of unvested common units granted under the Partnership’s long-term incentive plan (“LTIP”).
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. The non-controlling interest, which represents OpCo common unitholders’, as defined below, are not subject to federal income taxes. 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, 2023, 2022 and 2021. The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2023, 2022 and 2021, 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, 2023, 2022 and 2021, the Partnership’s top Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. While the Partnership does not require the counterparties to its derivative contracts to post collateral, the Partnership does evaluate the credit standing of such counterparties as they deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information.
Non-controlling Interest	Non-controlling Interest Non-controlling interest in the accompanying consolidated financial statements represents OpCo common unitholders’, as defined below, ownership in the net assets of the Operating Company. When the OpCo common unitholders’ relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 10—Unitholders’ Equity and Partnership Distributions for further discussion.
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. The following table disaggregates the Partnership’s oil, natural gas, and NGL revenues for the following periods: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 2022 ​ 2021 Oil revenue ​ $ 183,150,517 ​ $ 130,811,485 ​ $ 87,151,724 Natural gas revenue ​ ​ 59,524,413 ​ ​ 122,632,983 ​ ​ 66,977,352 NGL revenue ​ ​ 24,909,855 ​ ​ 28,519,658 ​ ​ 20,958,945 Total Oil, natural gas and NGL revenues ​ $ 267,584,785 ​ $ 281,964,126 ​ $ 175,088,021 ​ 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.
Consolidation	Consolidation The Partnership analyzes whether it has a variable interest in an entity and whether that entity is a variable interest entity (“VIE”) to determine whether it is required to consolidate those entities. The Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of all entities with respect to which the Partnership serves as the sponsor, general partner or managing member, and general partner entities not wholly owned by the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required. In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment. For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis. VIEs of which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.
Investments Held in Trust by Consolidated Variable Interest Entities	Investments Held in Trust by Consolidated Variable Interest Entities Investments held in trust represent funds raised by TGR (as defined in Note 3), a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 3). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and presented on the balance sheets at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities were included in other income (expense)—interest earned on marketable securities in trust account on the accompanying consolidated statements of operations. The estimated fair values of investments held in the trust account were determined using quoted prices in an active market and therefore classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements.
Redeemable Non-Controlling Interest	Redeemable Non-Controlling Interest Redeemable non-controlling interests represented the shares of Class A common stock of TGR par value $0.0001 per share (the “Class A common stock”) sold in the TGR IPO that were redeemable for cash by the public TGR shareholders that would have been concurrent with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests were initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. As of June 30, 2023, the shares had been redeemed in full.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements In March 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-01, “Leases (Topic 842): Common Control Arrangements.” This update requires that (i) entities determine whether a related party arrangement between entities under common control is a lease and (ii) that leasehold improvements have an amortization period consistent with the shorter of the remaining lease term and the useful life of the improvements, which is an approach that is largely consistent with legacy guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2023, including interim periods within that fiscal year. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 820): Improvements to Reportable Segment Disclosures.” The amendments in this update apply to all public entities that are required to report segment information in accordance with Topic 280, Segment Reporting. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity. In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. For entities other than public business entities, the amendments are effective for annual periods beginning after December 15, 2025. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2023
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Schedule of disaggregation of revenues	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 2022 ​ 2021 Oil revenue ​ $ 183,150,517 ​ $ 130,811,485 ​ $ 87,151,724 Natural gas revenue ​ ​ 59,524,413 ​ ​ 122,632,983 ​ ​ 66,977,352 NGL revenue ​ ​ 24,909,855 ​ ​ 28,519,658 ​ ​ 20,958,945 Total Oil, natural gas and NGL revenues ​ $ 267,584,785 ​ $ 281,964,126 ​ $ 175,088,021

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2023
DERIVATIVES
Schedule of changes in fair value of derivative instruments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Beginning fair value of derivative instruments ​ $ (12,324,076) ​ $ (26,624,646) ​ $ (6,280,863) Gain (loss) on commodity derivative instruments, net ​ ​ 20,888,972 ​ ​ (32,240,915) ​ ​ (41,240,942) Net cash paid on settlements of derivative instruments ​ ​ 5,482,086 ​ ​ 46,541,485 ​ ​ 20,897,159 Ending fair value of derivative instruments ​ $ 14,046,982 ​ $ (12,324,076) ​ $ (26,624,646)
Schedule of derivative contracts	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ December 31, Classification ​ Balance Sheet Location ​ 2023 ​ 2022 Assets: ​ ​ ​ ​ ​ ​ ​ ​ Current assets ​ Derivative assets ​ $ 11,427,735 ​ $ — Long-term assets ​ Derivative assets ​ ​ 2,888,051 ​ ​ 754,786 Liabilities: ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ Derivative liabilities ​ ​ (208,710) ​ ​ (12,646,720) Long-term liabilities ​ Derivative liabilities ​ ​ (60,094) ​ ​ (432,142) ​ ​ ​ ​ $ 14,046,982 ​ $ (12,324,076)
Schedule of commodity derivative contracts	Oil Price Swaps ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Notional ​ Weighted Average ​ Range (per Bbl) ​ ​ Volumes (Bbl) ​ Fixed Price (per Bbl) ​ Low ​ High January 2024 - December 2024 ​ 568,926 ​ $ 79.04 ​ $ 69.30 ​ $ 85.34 January 2025 - December 2025 ​ 563,526 ​ $ 70.36 ​ $ 64.35 ​ $ 77.01 Natural Gas Price Swaps ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Notional ​ Weighted Average ​ Range (per MMBtu) ​ ​ Volumes (MMBtu) ​ Fixed Price (per MMBtu) ​ Low ​ High January 2024 - December 2024 ​ 5,285,182 ​ $ 3.97 ​ $ 3.06 ​ $ 4.48 January 2025 - December 2025 ​ 5,153,291 ​ $ 3.81 ​ $ 3.50 ​ $ 4.37 ​

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ 14,315,786 ​ $ — ​ $ — ​ $ 14,315,786 Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ (268,804) ​ $ — ​ $ — ​ $ (268,804) December 31, 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ 754,786 ​ $ — ​ $ — ​ $ 754,786 Assets of consolidated variable interest entities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Investments held in trust ​ $ 240,621,146 ​ $ — ​ $ — ​ $ — ​ $ 240,621,146 Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivative contracts ​ $ — ​ $ (13,078,862) ​ $ — ​ $ — ​ $ (13,078,862) ​

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2023
OIL AND NATURAL GAS PROPERTIES
Schedule of oil and natural gas properties	​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ December 31, ​ ​ 2023 ​ 2022 Oil and natural gas properties ​ ​ ​ ​ ​ ​ Proved properties ​ $ 1,825,977,244 ​ $ 1,258,290,375 Unevaluated properties ​ ​ 222,712,844 ​ ​ 207,695,343 Less: accumulated depreciation, depletion and impairment ​ ​ (827,033,944) ​ ​ (712,716,951) Total oil and natural gas properties ​ $ 1,221,656,144 ​ $ 753,268,767

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2023
LEASES
Schedule of future minimum lease commitments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ 2024 ​ 2025 ​ 2026 ​ 2027 ​ 2028 ​ Thereafter Operating leases ​ $ 2,712,673 ​ $ 488,725 ​ $ 497,033 ​ $ 507,648 ​ $ 511,917 ​ $ 496,785 ​ $ 210,565 Less: Imputed Interest ​ (476,273) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ $ 2,236,400 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

UNITHOLDERS' EQUITY AND PARTN_2

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Tables)	12 Months Ended
	Dec. 31, 2023
Common units
Schedule of distributions approved by the Board of Directors	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amount per ​ Date ​ Unitholder ​ Payment ​ ​ Common Unit ​ Declared ​ Record Date ​ Date Q1 2023 ​ $ 0.35 ​ May 3, 2023 ​ May 15, 2023 ​ May 22, 2023 Q2 2023 ​ $ 0.39 ​ August 2, 2023 ​ August 14, 2023 ​ August 21, 2023 Q3 2023 ​ $ 0.51 ​ November 2, 2023 ​ November 13, 2023 ​ November 20, 2023 Q4 2023 ​ $ 0.43 ​ February 21, 2024 ​ March 13, 2024 ​ March 20, 2024 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Q1 2022 ​ $ 0.47 ​ April 22, 2022 ​ May 2, 2022 ​ May 9, 2022 Q2 2022 ​ $ 0.55 ​ August 3, 2022 ​ August 15, 2022 ​ August 22, 2022 Q3 2022 ​ $ 0.49 ​ November 3, 2022 ​ November 14, 2022 ​ November 21, 2022 Q4 2022 ​ $ 0.48 ​ February 23, 2023 ​ March 9, 2023 ​ March 16, 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​
Common Units
Common units
Schedule of changes in Partnership's units	​ ​ ​ ​ ​ ​ Common Units Balance at December 31, 2022 ​ 64,231,833 Common units issued under the A&R LTIP (1) ​ 998,162 Restricted units repurchased for tax withholding ​ (279,662) Common unit issued for acquisition ​ 557,302 Common units issued for equity offering ​ 8,337,500 Conversion of Class B units ​ 6,323 Balance at December 31, 2023 ​ 73,851,458 (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 “A&R LTIP”) on February 21, 2023.
Class B
Common units
Schedule of changes in Partnership's units	​ ​ ​ ​ ​ ​ Class B Units Balance at December 31, 2022 ​ 15,484,400 Class B units issued for acquisition ​ 5,369,218 Conversion of Class B units ​ (6,323) Balance at December 31, 2023 ​ 20,847,295

EARNINGS PER COMMON UNIT (Table

EARNINGS PER COMMON UNIT (Tables)	12 Months Ended
	Dec. 31, 2023
EARNINGS PER COMMON UNIT
Schedule of earnings per common unit	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Net income attributable to common units of Kimbell Royalty Partners, LP ​ $ 60,141,679 ​ $ 111,929,491 ​ $ 22,615,021 Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions ​ ​ 1,572,737 ​ ​ (17,412,732) ​ ​ — Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions ​ ​ 61,714,416 ​ ​ 94,516,759 ​ ​ 22,615,021 Distribution and accretion on Series A preferred units ​ ​ 6,310,215 ​ ​ — ​ ​ ​ Net income attributable to non-controlling interests in OpCo and distribution on Class B units ​ ​ 16,553,676 ​ ​ 18,864,795 ​ ​ 8,496,104 Diluted net income attributable to common units of Kimbell Royalty Partners, LP ​ $ 84,578,307 ​ $ 113,381,554 ​ $ 31,111,125 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of common units outstanding: ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ ​ 66,595,273 ​ ​ 54,112,595 ​ ​ 40,400,907 Effect of dilutive securities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Series A preferred units ​ ​ 6,499,350 ​ ​ — ​ ​ — Class B units ​ ​ 18,851,387 ​ ​ 10,819,266 ​ ​ 18,839,607 Restricted units ​ ​ 1,111,721 ​ ​ 905,156 ​ ​ 1,717,310 Diluted ​ ​ 93,057,731 ​ ​ 65,837,017 ​ ​ 60,957,824 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income per unit attributable to common units of Kimbell Royalty Partners, LP ​ ​ ​ ​ ​ ​ ​ ​ ​ Basic ​ $ 0.93 ​ $ 1.75 ​ $ 0.56 Diluted ​ $ 0.91 ​ $ 1.72 ​ $ 0.51

UNIT-BASED COMPENSATION (Tables

UNIT-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2022 ​ 1,897,192 ​ $ 13.553 1.517 years Awarded ​ 998,162 ​ ​ 15.020 ​ — Vested ​ (943,924) ​ ​ 12.602 ​ — Unvested at December 31, 2023 ​ 1,951,430 ​ $ 14.763 1.525 years ​

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2023
INCOME TAXES
Schedule of income tax expense	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Current ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ $ 2,469,584 ​ $ 2,412,702 ​ $ 69,067 State ​ ​ 1,296,718 ​ ​ 326,000 ​ ​ 5,033 Total Current ​ ​ 3,766,302 ​ ​ 2,738,702 ​ ​ 74,100 Deferred ​ ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ ​ — ​ ​ — ​ ​ — State ​ ​ — ​ ​ — ​ ​ — Total Deferred ​ ​ — ​ ​ — ​ ​ — Provision for income taxes ​ $ 3,766,302 ​ $ 2,738,702 ​ $ 74,100
Schedule of effective income expense	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Net income before taxes ​ $ 86,771,872 ​ ​ $ 133,532,988 ​ ​ $ 42,511,974 ​ Statutory rate ​ ​ 21 % ​ ​ 21 % ​ ​ 21 % Income tax provision computed at statutory rate ​ ​ 18,222,093 ​ ​ ​ 28,041,927 ​ ​ ​ 8,927,515 ​ Reconciling items: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ State income taxes ​ ​ 1,393,149 ​ ​ ​ 326,000 ​ ​ ​ 5,033 ​ Non-controlling interest ​ ​ (3,518,924) ​ ​ ​ (3,988,366) ​ ​ ​ (1,788,347) ​ Income at OpCo ​ ​ (14,703,170) ​ ​ ​ (24,053,561) ​ ​ ​ (7,139,168) ​ Change in valuation allowance - federal ​ ​ 2,860,951 ​ ​ ​ 2,202,314 ​ ​ ​ (363,132) ​ Change in valuation allowance - state ​ ​ (96,431) ​ ​ ​ (1,307,605) ​ ​ ​ (40,626) ​ Other, net ​ ​ (391,366) ​ ​ ​ 1,517,993 ​ ​ ​ 472,825 ​ Provision for income taxes ​ $ 3,766,302 ​ ​ $ 2,738,702 ​ ​ $ 74,100 ​
Schedule of components of deferred tax assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Deferred tax asset ​ ​ ​ ​ ​ ​ Outside basis in OpCo ​ $ 22,624,765 ​ $ 18,494,572 ​ $ 6,641,452 Federal tax loss carryforwards ​ ​ — ​ ​ 2,645,475 ​ ​ 12,296,282 State tax loss carryforwards ​ ​ 385,926 ​ ​ 482,356 ​ ​ 1,789,961 Business interest deduction limitation ​ ​ 1,376,234 ​ ​ — ​ ​ — Deferred tax asset ​ ​ 24,386,925 ​ ​ 21,622,403 ​ ​ 20,727,695 Valuation allowance ​ ​ (24,386,925) ​ ​ (21,622,403) ​ ​ (20,727,695) Net deferred tax asset ​ $ — ​ $ — ​ $ —

CORRECTION OF IMMATERIAL ERRO_2

CORRECTION OF IMMATERIAL ERRORS (Tables)	12 Months Ended
	Dec. 31, 2023
CORRECTION OF IMMATERIAL ERRORS
Schedule of effects of the adjustments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ ​ As Reported ​ Adjustments ​ As Adjusted Common units ​ $ 328,717,841 ​ $ (75,597,839) ​ $ 253,120,002 Class B units ​ ​ 880,579 ​ ​ — ​ ​ 880,579 Non-controlling interest in OpCo ​ ​ 19,251,361 ​ ​ 75,597,839 ​ ​ 94,849,200 Total unitholders' equity ​ $ 348,849,781 ​ $ — ​ $ 348,849,781 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 ​ ​ As Reported ​ Adjustments ​ As Adjusted Common units ​ $ 601,841,776 ​ $ (138,089,866) ​ $ 463,751,910 Class B units ​ ​ 774,220 ​ ​ — ​ ​ 774,220 Non-controlling interest in OpCo ​ ​ (26,106,320) ​ ​ 138,089,866 ​ ​ 111,983,546 Total unitholders' equity ​ $ 576,509,676 ​ $ — ​ $ 576,509,676 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2023 ​ ​ As Reported ​ Adjustments ​ As Adjusted Common units ​ $ 670,530,748 ​ $ (114,721,748) ​ $ 555,809,000 Class B units ​ ​ 1,042,365 ​ ​ — ​ ​ 1,042,365 Non-controlling interest in OpCo ​ ​ 42,470,067 ​ ​ 114,721,748 ​ ​ 157,191,815 Total unitholders' equity ​ $ 714,043,180 ​ $ — ​ $ 714,043,180
Schedule of changes in common unitholder's equity due to changes in ownership interest	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Net income attributable to the Partnership ​ $ 65,151,528 ​ $ 111,971,734 ​ $ 30,647,893 Changes in ownership of consolidated subsidiaries, net ​ ​ 23,421,490 ​ ​ 49,056,142 ​ ​ (12,295,407) Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest ​ $ 88,573,018 ​ $ 161,027,876 ​ ​ 18,352,486 ​

SUPPLEMENTAL OIL AND GAS RESE_2

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2023
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, ​ 2023 ​ 2022 Oil, natural gas and NGL interests ​ ​ ​ ​ ​ ​ Proved properties ​ $ 1,825,977,244 ​ $ 1,258,290,375 Unevaluated properties ​ ​ 222,712,844 ​ ​ 207,695,343 Total oil, natural gas and NGL interests ​ 2,048,690,088 ​ 1,465,985,718 Accumulated depreciation, depletion, accretion and impairment ​ (827,033,944) ​ (712,716,951) Net oil, natural gas and NGL interests capitalized ​ $ 1,221,656,144 ​ $ 753,268,767
Schedule of costs incurred in oil and natural gas activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Acquisition costs ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved properties ​ $ 260,145,370 ​ $ 56,848,235 ​ $ 55,300,252 Unevaluated properties ​ ​ 322,559,000 ​ ​ 204,742,000 ​ ​ — Total ​ 582,704,370 ​ 261,590,235 ​ 55,300,252 Development costs ​ ​ ​ Proved properties ​ — ​ — ​ — Total ​ — ​ — ​ — Total costs incurred on oil, natural gas and NGL activities ​ $ 582,704,370 ​ $ 261,590,235 ​ $ 55,300,252
Results of operations from oil, natural gas and natural gas liquids	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 Oil, natural gas and NGL revenues ​ $ 267,584,785 ​ $ 281,964,126 ​ $ 175,088,021 Lease bonus and other income ​ ​ 5,594,855 ​ ​ 3,073,609 ​ ​ 3,319,104 Production and ad valorem taxes ​ (20,326,477) ​ (16,238,814) ​ (10,480,481) Depreciation and depletion expense ​ (96,477,003) ​ (50,086,414) ​ (36,797,881) Impairment of oil and natural gas properties ​ (18,220,173) ​ — ​ — Marketing and other deductions ​ (12,564,619) ​ (13,383,074) ​ (12,048,643) Results of operations from oil, natural gas and NGLs ​ $ 125,591,368 ​ $ 205,329,433 ​ $ 119,080,120
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, 2021 ​ 12,294 ​ 144,233 ​ 6,085 ​ 42,418 Revisions of previous estimates (1) ​ 251 ​ 24,079 ​ 780 ​ 5,044 Purchase of minerals in place (2) ​ 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 Revisions of previous estimates (1) ​ (58) ​ 17,119 ​ 759 ​ 3,554 Purchase of minerals in place (3) ​ 1,328 ​ 5,726 ​ 707 ​ 2,989 Production ​ (1,426) ​ (20,311) ​ (747) ​ (5,558) Net proved reserves at December 31, 2022 ​ 12,355 ​ 160,298 ​ 7,388 ​ 46,459 Revisions of previous estimates (1) ​ 3,273 ​ 26,068 ​ 814 ​ 8,432 Purchase of minerals in place (4) ​ 6,565 ​ 41,560 ​ 4,400 ​ 17,892 Production ​ (2,393) ​ (23,384) ​ (1,083) ​ (7,374) Net proved reserves at December 31, 2023 ​ 19,800 ​ 204,542 ​ 11,519 ​ 65,409 ​ ​ ​ ​ ​ ​ ​ ​ ​ Net proved developed reserves ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ 12,511 ​ 157,764 ​ 6,669 ​ 45,474 December 31, 2022 ​ 12,355 ​ 160,298 ​ 7,388 ​ 46,459 December 31, 2023 ​ 19,800 ​ 204,542 ​ 11,519 ​ 65,409 (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 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. (3) Includes the acquisition of mineral and royalty interests for a total of $56.8 million, primarily consisting of mineral and royalty interests in the Permian Basin. (4) Includes the acquisition of mineral and royalty interests, primarily consisting of mineral and royalty interests in the Permian Basin and Mid-Continent.
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, ​ 2023 ​ 2022 ​ 2021 Future cash inflows ​ $ 2,226,313 ​ $ 2,253,273 ​ $ 1,335,917 Future production costs ​ ​ (164,848) ​ ​ (161,676) ​ ​ (100,947) Future state margin taxes ​ ​ (49,144) ​ ​ (76,322) ​ ​ (42,965) Future net cash flows ​ ​ 2,012,321 ​ ​ 2,015,275 ​ ​ 1,192,005 Less 10% annual discount to reflect timing of cash flows ​ ​ (1,037,192) ​ ​ (1,110,980) ​ ​ (665,390) Standard measure of discounted future net cash flows ​ $ 975,129 ​ $ 904,295 ​ $ 526,615
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, ​ ​ 2023 ​ 2022 ​ 2021 Standardized measure - beginning of year ​ $ 904,295 ​ $ 526,615 ​ $ 284,996 Sales, net of production costs ​ ​ (236,953) ​ ​ (252,597) ​ ​ (152,751) Net changes of prices and production costs related to future production ​ ​ (302,599) ​ ​ 365,427 ​ ​ 225,868 Revisions of previous quantity estimates, net of related costs ​ ​ 128,727 ​ ​ 71,776 ​ ​ 60,517 Net changes in state margin taxes ​ ​ 10,433 ​ ​ (15,266) ​ ​ (8,665) Accretion of discount ​ ​ 78,425 ​ ​ 44,280 ​ ​ 25,743 Purchases of reserves in place ​ ​ 435,230 ​ ​ 77,719 ​ ​ 40,545 Timing differences and other ​ ​ (42,429) ​ ​ 86,341 ​ ​ 50,362 Standardized measure - end of year ​ $ 975,129 ​ $ 904,295 ​ $ 526,615 ​

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Details)	12 Months Ended
	Dec. 31, 2023 segment
Segment Reporting
Number of operating units	1
Number of reporting units	1

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property and Equipment (Details)	Dec. 31, 2023
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, 2023	Dec. 31, 2022	Dec. 31, 2021
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, 2023	Dec. 31, 2022	Dec. 31, 2021
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Concentration of Credit Risk
Number of significant purchasers	1
Operator 1
Concentration of Credit Risk
Purchaser percentage	6.70%	11.30%	6%

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue
Total revenue	$ 267,584,785	$ 281,964,126	$ 175,088,021
Oil revenue
Revenue
Total revenue	183,150,517	130,811,485	87,151,724
Natural gas revenue
Revenue
Total revenue	59,524,413	122,632,983	66,977,352
NGL revenue
Revenue
Total revenue	$ 24,909,855	$ 28,519,658	$ 20,958,945

SUMMARY OF SIGNIFICANT ACCOUN_9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue from Contracts with Customers (Details)	12 Months Ended
	Dec. 31, 2023
Minimum
Settlement period for certain natural gas and natural gas liquids sales	1 month
Maximum
Settlement period for certain natural gas and natural gas liquids sales	4 months

SUMMARY OF SIGNIFICANT ACCOU_10

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Feb. 08, 2022
Accounts Receivable
Allowance for doubtful accounts receivable	$ 0	$ 0
Kimbell Tiger Acquisition Corporation | Class A
Accounts Receivable
Common Stock par value (in dollars per share)			$ 0.0001

ACQUISITIONS, JOINT VENTURES _2

ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY - Acquisitions (Details)

12 Months Ended

Sep. 13, 2023 USD ($)

May 22, 2023 USD ($)

May 17, 2023 USD ($) shares

May 08, 2023 item

Feb. 08, 2023 USD ($)

Dec. 15, 2022 USD ($) a shares

Dec. 07, 2021 USD ($) item

Mar. 10, 2021 USD ($)

Dec. 31, 2023 USD ($) shares

Dec. 31, 2022 USD ($)

Dec. 31, 2021 USD ($)

Feb. 08, 2022 $ / shares

Jun. 19, 2019

Acquisitions

Common units sold to public

$ 110,711,383

$ 116,119,417

$ 57,522,440

Assets

1,337,789,216

1,076,746,299

Liabilities

$ 309,322,464

263,336,623

Purchase and sale agreement | Royalty, mineral and overriding interests

Acquisitions

Total purchase price

15,000,000

Net proceeds realized

$ 6,500,000

Kimbell Tiger Acquisition Corporation | IPO

Acquisitions

Common units sold to public

$ 230,000,000

Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP.

Acquisitions

Ownership interest (as a percent)

49.30%

Kimbell Tiger Acquisition Corporation

Acquisitions

Redemption of equity in variable interest entity

$ 1,600,000

Period for each business combination extension

3 months

Number of business combination extensions | item

2

Common Units

Acquisitions

Common units issued for equity offering (in units) | shares

8,337,500

Class A | Kimbell Tiger Acquisition Corporation

Acquisitions

Common Stock par value (in dollars per share) | $ / shares

$ 0.0001

LongPoint Minerals II, LLC

Acquisitions

Purchase price cash, gross

$ 455,000,000

Transactional costs

7,400,000

Post-effective net oil, natural gas and NGL revenues earned prior to the closing date

16,600,000

Acquisition asset allocation

Proved properties

198,200,000

Unevaluated properties

$ 247,600,000

Nail Bay Royalties

Acquisitions

Purchase price cash, gross

$ 500,000

2021 Acquisitions

Acquisition asset allocation

Proved properties

$ 55,300,000

Caritas Royalty Fund, LLC

Acquisitions

Transaction value of acquisition

$ 54,600,000

Number of gross producing wells being operated. | item

26,000

Hatch Royalties, LLC

Acquisitions

Cash paid to acquire businesses, net of cash acquired and transaction costs

$ 150,400,000

Gross acres acquired (in acres) | a

230,000

Net royalty acres acquired (in acres) | a

889

Acquisition asset allocation

Proved properties

$ 56,400,000

Unevaluated properties

$ 204,700,000

Hatch Royalties, LLC | Capital Unit Class B

Acquisitions

Business Acquisition issuance of common units | shares

7,272,821

Hatch Royalties, LLC | OpCo Units

Acquisitions

Business Acquisition issuance of common units | shares

7,272,821

MB Minerals, L.P.

Acquisitions

Purchase price cash, gross

$ 48,800,000

Acquisition asset allocation

Proved properties

60,800,000

Unevaluated properties

$ 74,900,000

MB Minerals, L.P. | OpCo Units

Acquisitions

Business Acquisition issuance of common units | shares

5,369,218

MB Minerals, L.P. | Class B Common Units

Acquisitions

Business Acquisition issuance of common units | shares

557,302

DERIVATIVES (Details)

DERIVATIVES (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) $ / bbl bbl MMBbls	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	May 17, 2022	Jan. 27, 2021 USD ($)
Change in fair values of derivative instruments
Beginning fair value of commodity derivative instruments | $	$ (12,324,076)	$ (26,624,646)	$ (6,280,863)
Gain (loss) on commodity derivative instruments, net | $	20,888,972	(32,240,915)	(41,240,942)
Net cash paid on settlements of derivative instruments | $	5,482,086	46,541,485	20,897,159
Ending fair value of commodity derivative instruments | $	14,046,982	(12,324,076)	(26,624,646)
Assets:
Current assets | $	11,427,735
Long-term assets | $	2,888,051	754,786
Liabilities:
Current liability | $	(208,710)	(12,646,720)
Long-term liability | $	(60,094)	(432,142)
Derivative assets (liabilities) | $	$ 14,046,982	(12,324,076)	(26,624,646)
Interest Rate Swap
Derivatives
Derivative, Notional Amount | $			150,000,000		$ 150,000,000
Unwind notional amount (as a percent)				50%
Change in fair values of derivative instruments
Gain on interest rate swap | $		$ 6,400,000
Liabilities:
Derivative Asset | $			$ 1,800,000
Oil Price Swaps - January 2024 - December 2024
Derivatives
Notional Volumes | bbl	568,926
Weighted Average Fixed Price | $ / bbl	79.04
Oil Price Swaps - January 2025 - December 2025
Derivatives
Notional Volumes | bbl	563,526
Weighted Average Fixed Price | $ / bbl	70.36
Natural Gas Price Swaps - January 2024 - December 2024
Derivatives
Notional Volumes | MMBbls	5,285,182
Weighted Average Fixed Price | $ / bbl	3.97
Natural Gas Price Swaps - January 2025 - December 2025
Derivatives
Notional Volumes | MMBbls	5,153,291
Weighted Average Fixed Price | $ / bbl	3.81
Minimum | Oil Price Swaps - January 2024 - December 2024
Derivatives
Weighted Average Fixed Price | $ / bbl	69.30
Minimum | Oil Price Swaps - January 2025 - December 2025
Derivatives
Weighted Average Fixed Price | $ / bbl	64.35
Minimum | Natural Gas Price Swaps - January 2024 - December 2024
Derivatives
Weighted Average Fixed Price | $ / bbl	3.06
Minimum | Natural Gas Price Swaps - January 2025 - December 2025
Derivatives
Weighted Average Fixed Price | $ / bbl	3.50
Maximum | Oil Price Swaps - January 2024 - December 2024
Derivatives
Weighted Average Fixed Price | $ / bbl	85.34
Maximum | Oil Price Swaps - January 2025 - December 2025
Derivatives
Weighted Average Fixed Price | $ / bbl	77.01
Maximum | Natural Gas Price Swaps - January 2024 - December 2024
Derivatives
Weighted Average Fixed Price | $ / bbl	4.48
Maximum | Natural Gas Price Swaps - January 2025 - December 2025
Derivatives
Weighted Average Fixed Price | $ / bbl	4.37

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Commodity Derivative contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets	$ 14,315,786	$ 754,786
Derivative contracts liabilities	(268,804)	(13,078,862)
Commodity Derivative contract | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets	14,315,786	754,786
Derivative contracts liabilities	$ (268,804)	(13,078,862)
Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets			$ 1,800,000
Assets Held In Trust | Consolidated variable interest entities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets		240,621,146
Assets Held In Trust | Level 1 | Consolidated variable interest entities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets		$ 240,621,146

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
OIL AND NATURAL GAS PROPERTIES
Proved properties	$ 1,825,977,244	$ 1,258,290,375
Unevaluated properties	222,712,844	207,695,343
Less: accumulated depreciation, depletion, and impairment	(827,033,944)	(712,716,951)
Total oil and natural gas properties, net	1,221,656,144	753,268,767
Impairment of oil and natural gas properties	$ 18,220,173	$ 0	$ 0

OIL AND NATURAL GAS PROPERTIE_3

OIL AND NATURAL GAS PROPERTIES - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2023	Dec. 31, 2023 $ / bbl	Dec. 31, 2023 $ / Mcf	Dec. 31, 2022 USD ($)	Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / Mcf	Dec. 31, 2021 USD ($) $ / bbl
Oil and natural gas properties
Net revenues discounting percentage at future		10%
Impairment of oil and natural gas properties | $	$ 18,220,173				$ 0			$ 0
Crude Oil
Oil and natural gas properties
Average sales prices | $ / bbl			78.22			93.67		66.56
Percentage of average prices of oil and natural gas		16.50%
Natural Gas
Oil and natural gas properties
Average sales prices			2.64	2.64		6.36	6.36	3.60
Percentage of average prices of oil and natural gas		58.50%

LEASES (Details)

LEASES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
LEASES
Operating lease weighted average remaining lease term	5 years 5 months 4 days
Operating lease weighted average discount rate (as a percent)	6.75%
Operating lease expense	$ 600,000	$ 500,000	$ 400,000
2024	488,725
2025	497,033
2026	507,648
2027	511,917
2028	496,785
Thereafter	210,565
Total operating leases	2,712,673
Less Imputed Interest	(476,273)
Total	$ 2,236,400

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($)		12 Months Ended
	Jun. 13, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 08, 2023	Dec. 07, 2023	Jul. 24, 2023	Jul. 23, 2023
Long-term debt
Minimum percentage of proved reserves constituting borrowings based properties (as a percent)		75%
Amortization of Debt Issuance Costs		$ 1,943,025	$ 1,872,700	$ 1,556,769
Debt extinguishment		500,000
Borrowings of debt		201,084,089	199,200,000	136,565,769
Repayment of debt		139,900,000	$ 183,300,000	$ 91,000,000
Revolving credit facility
Long-term debt
Borrowing base					$ 550,000,000	$ 400,000,000
Revolving credit facility outstanding		$ 294,200,000
Excess cash determinations							$ 50,000,000	$ 30,000,000
Interest rate on outstanding borrowings (as a percent)		8.62%
Borrowings of debt		$ 201,100,000
Repayment of debt		$ 139,900,000
Revolving credit facility | Prime
Long-term debt
Margin (as a percent)		2.25%
Revolving credit facility | SOFR
Long-term debt
Margin (as a percent)		3.25%
Variable rate		SOFR
Revolving credit facility | Maximum
Long-term debt
Debt to EBITDAX ratio		3.50%
Revolving credit facility | Minimum
Long-term debt
Current assets to current liabilities ratio		1%
Standby and/or commercial letters of credit
Long-term debt
Revolving credit facility maximum borrowings	$ 10,000,000
Revolving credit facility outstanding		$ 0
Senior Secured Reserve Based Revolving Credit Facility
Long-term debt
Revolving credit facility maximum borrowings	750,000,000
Borrowing base	400,000,000
Initial aggregate elected commitments amount	400,000,000
Minimum cash balance required to be applied weekly to prepay loans	50,000,000
Reduced cash balance as permitted by agreement	$ 0
Commitment fees (as a percent)	0.50%
Senior Secured Reserve Based Revolving Credit Facility | Maximum | SOFR
Long-term debt
Margin (as a percent)	3.75%
Senior Secured Reserve Based Revolving Credit Facility | Maximum | Base Rate
Long-term debt
Margin (as a percent)	2.75%
Senior Secured Reserve Based Revolving Credit Facility | Minimum | SOFR
Long-term debt
Margin (as a percent)	2.75%
Senior Secured Reserve Based Revolving Credit Facility | Minimum | Base Rate
Long-term debt
Margin (as a percent)	1.75%

PREFERRED UNITS - Other (Detail

PREFERRED UNITS - Other (Details)			12 Months Ended
	Sep. 13, 2023 USD ($) item D $ / shares shares	Aug. 02, 2023 shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2021 USD ($)	Dec. 31, 2022 shares
Preferred units
Temporary equity, issued (in units)			325,000		0
Liquidation preference rate (in percentage)	10%
Increased distribution rate	20%
Series A preferred units deemed distributions | $			$ 6,310,215	$ 11,249,969
Temporary equity, outstanding (in units)			325,000		0
Series A Preferred Units
Preferred units
The period after issuance securities become convertible	7 years
Percentage of cash distributions per annum	6%
Number of members of board | item	2
Ownership required to grant the approval	66.67%
Ratio of return on investment to preferred units	1.2
Series A Preferred Units | Series A Issuance Date
Preferred units
Minimum internal rate of return (as percent)	12%
Series A Preferred Units | On or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary
Preferred units
Minimum internal rate of return (as percent)	13%
Series A Preferred Units | On or after the sixth anniversary
Preferred units
Minimum internal rate of return (as percent)	14%
Series A Preferred Units | Minimum | The Partnership
Preferred units
Aggregate value of common units to be issued for preferred units | $	$ 10,000,000
Percentage of closing price to the conversion price	160%
Threshold trading days for transfer, assign or sale of units preceding the conversion notice | D	20
Threshold consecutive trading days for transfer, assign or sale of units preceding the conversion notice | D	30
Affiliates of Apollo Capital Management, L.P. | LongPoint Minerals II, LLC
Preferred units
Series A preferred units issued	325,000
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Units | Kimbell Royalty Operating, LLC
Preferred units
Temporary equity, issued (in units)	325,000
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Units | LongPoint Minerals II, LLC
Preferred units
Share price (in dollars per unit) | $ / shares	$ 1,000
Proceeds from the issuance of preferred units | $	$ 325,000,000
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Stock
Preferred units
Series A preferred units issued		400,000
Series A Purchasers | Minimum
Preferred units
Percentage of closing price to the conversion price	130%
Conversion price of units | $ / shares	$ 15.07
Series A Purchasers | Series A Preferred Units | Minimum
Preferred units
Aggregate value of common units to be issued for preferred units | $	$ 10,000,000
Threshold trading days for transfer, assign or sale of units preceding the conversion notice | D	20
Threshold consecutive trading days for transfer, assign or sale of units preceding the conversion notice | D	30

UNITHOLDERS' EQUITY AND PARTN_3

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Details) - USD ($)		1 Months Ended		3 Months Ended												12 Months Ended
	Aug. 07, 2023	Nov. 30, 2022	Nov. 30, 2021	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Common units
Units issued (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Units outstanding (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Repayment of debt																$ 139,900,000	$ 183,300,000	$ 91,000,000
Capital rollforward
Unitholders' capital, beginning balance (in units)							64,231,833									64,231,833
Unitholders' capital, ending balance (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Cash distributions declared and paid (in dollars per unit)				$ 0.43	$ 0.51	$ 0.39	$ 0.35	$ 0.48	$ 0.49	$ 0.55	$ 0.47	$ 0.37	$ 0.37	$ 0.31	$ 0.27
Common Units
Common units
Units issued (in units)				73,851,458												73,851,458
Units outstanding (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Capital rollforward
Unitholders' capital, beginning balance (in units)							64,231,833									64,231,833
Common units issued under the A&R LTIP (in units)																998,162
Restricted units repurchased for tax withholding (in units)																(279,662)
Common unit issued for acquisition (in units)																557,302
Common units issued for equity offering (in units)																8,337,500
Conversion of Class B Units (in units)																6,323
Unitholders' capital, ending balance (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Class B
Common units
Units outstanding (in units)				20,847,295				15,484,400								20,847,295	15,484,400
Capital rollforward
Unitholders' capital, beginning balance (in units)							15,484,400									15,484,400
Class B units issued for Drop Down acquisition																5,369,218
Conversion of Class B Units (in units)							(6,323)
Unitholders' capital, ending balance (in units)				20,847,295				15,484,400								20,847,295	15,484,400
Cash distributions (as a percent)																2%
Additional consideration paid per unit (in dollars per unit)																$ 0.05
Public Offering
Common units
Units issued (in units)	8,337,500	6,900,000	4,312,500
Proceeds from equity offering	$ 110,700,000	$ 116,100,000	$ 57,700,000
Repayment of debt	$ 90,000,000	$ 116,000,000	$ 56,000,000

EARNINGS PER COMMON UNIT (Detai

EARNINGS PER COMMON UNIT (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings per unit
Net income attributable to common units of Kimbell Royalty Partners, LP	$ 60,141,679	$ 111,929,491	$ 22,615,021
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions	(1,572,737)	17,412,732
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions	61,714,416	94,516,759	22,615,021
Distribution and accretion on Series A preferred units	6,310,215		11,249,969
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$ 84,578,307	$ 113,381,554	$ 31,111,125
Weighted average number of common units outstanding Basic (in units)	66,595,273	54,112,595	40,400,907
Weighted average number of common units outstanding Diluted (in units)	93,057,731	65,837,017	60,957,824
Net income per unit attributable to common units (basic) (in dollar per share)	$ 0.93	$ 1.75	$ 0.56
Net income per unit attributable to common units (diluted) (in dollar per share)	$ 0.91	$ 1.72	$ 0.51
Series A Preferred Units
Earnings per unit
Net income attributable to non-controlling interests in OpCo and distribution on Class B units	$ 16,553,676	$ 18,864,795	$ 8,496,104
Weighted average number of common units outstanding (in units)	6,499,350
Restricted Units
Earnings per unit
Weighted average number of common units outstanding (in units)	1,111,721	905,156	1,717,310
Class B
Earnings per unit
Weighted average number of common units outstanding (in units)	18,851,387	10,819,266	18,839,607

UNIT-BASED COMPENSATION (Detail

UNIT-BASED COMPENSATION (Details) - Long-Term Incentive Plan - $ / shares		12 Months Ended
	May 18, 2022	Dec. 31, 2023	Dec. 31, 2022
Unit-based compensation
Additional common units authorized for issuance	3,700,000
Vesting period		3 years
Authorized issuance of units	8,241,600
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)		1,897,192
Awarded (in units)		998,162
Vesting (in units)		(943,924)
Unvested at end of period (in units)		1,951,430	1,897,192
Unvested Weighted Average Grant-Date Fair Value
Unvested at beginning of period (in dollars per unit)		$ 13.553
Awarded (in dollars per unit)		15.020
Vesting (in dollars per unit)		12.602
Unvested at end of period (in dollars per unit)		$ 14.763	$ 13.553
Weighted Average Remaining Contractual Term
Unvested contractual term, at end of period		1 year 6 months 9 days	1 year 6 months 6 days

INCOME TAXES - (Details)

INCOME TAXES - (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
INCOME TAXES
Effective income tax rate (as a percent)	4.34%
Income tax expense	$ 3,766,302	$ 2,738,702	$ 74,100

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current
Federal	$ 2,469,584	$ 2,412,702	$ 69,067
State	1,296,718	326,000	5,033
Total Current	3,766,302	2,738,702	74,100
Deferred
Provision for income taxes	$ 3,766,302	$ 2,738,702	$ 74,100

INCOME TAXES - Reconciliation (

INCOME TAXES - Reconciliation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of the provision for income taxes at statutory rates to the provision for income taxes at the effective tax rate
Net income before taxes	$ 86,771,872	$ 133,532,988	$ 42,511,974
Statutory rate (as a percent)	21%	21%	21%
Income tax provision computed at statutory rate	$ 18,222,093	$ 28,041,927	$ 8,927,515
State income taxes	1,393,149	326,000	5,033
Non-controlling interest	(3,518,924)	(3,988,366)	(1,788,347)
Income at OpCo	(14,703,170)	(24,053,561)	(7,139,168)
Change in valuation allowance - federal	2,860,951	2,202,314	(363,132)
Change in valuation allowance - state	(96,431)	(1,307,605)	(40,626)
Other, net	(391,366)	1,517,993	472,825
Provision for income taxes	$ 3,766,302	$ 2,738,702	$ 74,100

INCOME TAXES - Deferred Taxes (

INCOME TAXES - Deferred Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Deferred tax asset
Outside basis in OpCo	$ 22,624,765	$ 18,494,572	$ 6,641,452
Federal tax loss carryforwards		2,645,475	12,296,282
State tax loss carryforwards	385,926	482,356	1,789,961
Business interest deduction limitation	1,376,234
Deferred tax assets	24,386,925	21,622,403	20,727,695
Valuation allowance	(24,386,925)	(21,622,403)	(20,727,695)
Deferred tax liability
Outside basis investment in operating company valuation allowance	24,400,000
Uncertain tax positions	$ 0	$ 0	$ 0

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transactions
Total revenue	$ 294,068,612	$ 248,059,185	$ 135,615,216
Related Party
Related Party Transactions
Due from related parties	25,000
Total revenue	50,000
Related Party | BJF Royalties
Related Party Transactions
Payments made to related parties	0
Related Party | K3 Royalties
Related Party Transactions
Payments made to related parties	120,000
Related Party | Director And Officer Insurance To Partnership At Higginbotham Insurance Financial Services
Related Party Transactions
Related Party Transaction, Amounts of Transaction	26,500
Related Party Transactions, Annual Insurance Premium Expense	602,600
Related Party | Rivercrest Capital Management, LLC
Related Party Transactions
Related party expense reimbursement received	$ 180,626

ADMINISTRATIVE SERVICES (Detail

ADMINISTRATIVE SERVICES (Details) - LongPoint Acquisition	12 Months Ended
	Dec. 31, 2023 USD ($)
Transition Service Agreement amount of administrative services to be received	$ 250,000
Transition service fees incurred	$ 900,000

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - Subsequent Event - USD ($) $ / shares in Units, $ in Millions	Mar. 13, 2024	Feb. 21, 2024	Feb. 20, 2024	Feb. 19, 2024
OpCo Units
Subsequent events
Tax payment made from cash reserves per unit			$ 0.023897
Cash distributions declared (in dollars per unit)		$ 0.453897
Series A Preferred Stock
Subsequent events
Distribution Made to Limited Liability Company (LLC) Member, Cash Distributions Declared	$ 4.9
Common Units
Subsequent events
Cash distributions declared (in dollars per unit)		$ 0.43
Executive Officers
Subsequent events
Cash bonuses awarded				$ 2.5
Units issued for bonus compensation				1,087,502

CORRECTION OF IMMATERIAL ERRO_3

CORRECTION OF IMMATERIAL ERRORS - Effects of adjustments (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
CORRECTION OF IMMATERIAL ERRORS
Common units	$ 555,809,000	$ 463,751,910	$ 253,120,002
Class B units	1,042,365	774,220	880,579
Non-controlling interest in OpCo	157,191,815	111,983,546	94,849,200
Total unitholders' equity	714,043,180	576,509,676	348,849,781	$ 335,634,738
As Reported
CORRECTION OF IMMATERIAL ERRORS
Common units	670,530,748	601,841,776	328,717,841
Class B units	1,042,365	774,220	880,579
Non-controlling interest in OpCo	42,470,067	(26,106,320)	19,251,361
Total unitholders' equity	714,043,180	576,509,676	348,849,781
Adjustments
CORRECTION OF IMMATERIAL ERRORS
Common units	(114,721,748)	(138,089,866)	(75,597,839)
Non-controlling interest in OpCo	$ 114,721,748	$ 138,089,866	$ 75,597,839

CORRECTION OF IMMATERIAL ERRO_4

CORRECTION OF IMMATERIAL ERRORS - Changes in Ownership Interest (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CORRECTION OF IMMATERIAL ERRORS
Net income attributable to the Partnership	$ 65,151,528	$ 111,971,734	$ 30,647,893
Changes in ownership of consolidated subsidiaries	23,421,490	49,056,142	(12,295,407)
Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest	$ 88,573,018	$ 161,027,876	$ 18,352,486

SUPPLEMENTAL OIL AND GAS RESE_3

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Other Disclosures (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) segment	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Number of reporting segments | segment	1
Oil, natural gas and NGL interests
Proved properties	$ 1,825,977,244	$ 1,258,290,375
Unevaluated properties	222,712,844	207,695,343
Total oil, natural gas and NGL interest	2,048,690,088	1,465,985,718
Accumulated depreciation, depletion and impairment	(827,033,944)	(712,716,951)
Net oil, natural gas and NGL interests capitalized	1,221,656,144	753,268,767
Acquisition costs
Proved properties	260,145,370	56,848,235	$ 55,300,252
Unevaluated properties	322,559,000	204,742,000
Total	582,704,370	261,590,235	55,300,252
Developed costs
Total costs incurred on oil, natural gas and NGL activities	582,704,370	261,590,235	55,300,252
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities
Oil, natural gas and NGL revenue	267,584,785	281,964,126	175,088,021
Lease bonus and other income	5,594,855	3,073,609	3,319,104
Production and ad valorem taxes	(20,326,477)	(16,238,814)	(10,480,481)
Depreciation and depletion expense	(96,477,003)	(50,086,414)	(36,797,881)
Impairment of oil and natural properties	(18,220,173)
Marketing and other deductions	(12,564,619)	(13,383,074)	(12,048,643)
Results of operations form oil, natural gas and NGLs	$ 125,591,368	$ 205,329,433	$ 119,080,120

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, 2023 MBbls MMcf	Dec. 31, 2022 USD ($) MBbls MMcf	Dec. 31, 2021 USD ($) MBbls MMcf
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	46,459	45,474	42,418
Revisions of previous estimates	8,432	3,554	5,044
Purchase of minerals in place	17,892	2,989	3,252
Production	(7,374)	(5,558)	(5,240)
Net proved reserves at end of period	65,409	46,459	45,474
Net Proved Developed Reserves	65,409	46,459	45,474
Crude Oil and Condensate
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	12,355	12,511	12,294
Revisions of previous estimates	3,273	(58)	251
Purchase of minerals in place	6,565	1,328	1,310
Production	(2,393)	(1,426)	(1,344)
Net proved reserves at end of period	19,800	12,355	12,511
Net Proved Developed Reserves	19,800	12,355	12,511
Natural Gas
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period | MMcf	160,298	157,764	144,233
Revisions of previous estimates | MMcf	26,068	17,119	24,079
Purchase of minerals in place | MMcf	41,560	5,726	8,537
Production | MMcf	(23,384)	(20,311)	(19,085)
Net proved reserves at end of period | MMcf	204,542	160,298	157,764
Net Proved Developed Reserves | MMcf	204,542	160,298	157,764
Natural Gas Liquids
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	7,388	6,669	6,085
Revisions of previous estimates	814	759	780
Purchase of minerals in place	4,400	707	519
Production	(1,083)	(747)	(715)
Net proved reserves at end of period	11,519	7,388	6,669
Net Proved Developed Reserves	11,519	7,388	6,669
Permian Basin Mid-Continent Region [Member]
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $		$ 56.8	$ 55.3

SUPPLEMENTAL OIL AND GAS RESE_5

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Standardized Measure (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Standardized Measure
Future cash inflows	$ 2,226,313	$ 2,253,273	$ 1,335,917
Future production costs	(164,848)	(161,676)	(100,947)
Future state margin taxes	(49,144)	(76,322)	(42,965)
Future net cash flows	2,012,321	2,015,275	1,192,005
Less 10% annual discount to reflect timing of cash flows	(1,037,192)	(1,110,980)	(665,390)
Standard measure of discounted future net cash flows	$ 975,129	$ 904,295	$ 526,615	$ 284,996

SUPPLEMENTAL OIL AND GAS RESE_6

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Average Market Prices (Details)	12 Months Ended
	Dec. 31, 2023 $ / bbl	Dec. 31, 2023 $ / Mcf	Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / Mcf	Dec. 31, 2021 $ / bbl
Crude Oil and Condensate
Average Sales Prices
Average sales prices	78.22		93.67		66.56
Natural Gas
Average Sales Prices
Average sales prices	2.64	2.64	6.36	6.36	3.60

SUPPLEMENTAL OIL AND GAS RESE_7

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Changes in Standardized Measure (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Changes in Standardized Measure
Standardized measure - beginning of year	$ 904,295	$ 526,615	$ 284,996
Sales, net of production costs	(236,953)	(252,597)	(152,751)
Net changes of prices and production costs related to future production	(302,599)	365,427	225,868
Revisions of previous quantity estimates, net of related costs	128,727	71,776	60,517
Net changes in state margin taxes	10,433	(15,266)	(8,665)
Accretion of discount	78,425	44,280	25,743
Purchases of reserves in place	435,230	77,719	40,545
Timing differences and other	(42,429)	86,341	50,362
Standardized measure - end of year	$ 975,129	$ 904,295	$ 526,615