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DEBT - Schedule of Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Debt Disclosure [Abstract]
Interest expense	$ 103	$ 74	$ 48
Other fees and expenses	3	2	1
Less: interest income	10	2	2
Interest expense, net	$ 96	$ 74	$ 47

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
ORGANIZATION AND BASIS OF PRESENTATION	Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION Organization Viper Energy, Inc. is a publicly traded Delaware corporation. Viper (as defined below) and its consolidated subsidiaries are focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin. On August 19, 2025, upon completion of the Sitio Acquisition (as defined and discussed in Note 4—Acquisitions and Divestitures), VNOM Sub, Inc. (formerly known as Viper Energy Inc., “Former Viper”) became a wholly owned subsidiary of Viper Energy, Inc. (formerly known as New Cobra Pubco, Inc., “New Viper”), as a result of a merger contemplated by the documents governing the Sitio Acquisition (such merger, the “Viper PubCo Merger”). Upon completion of the Viper PubCo Merger, each share of Former Viper’s Class A common stock, par value $0.000001 per share, issued and outstanding immediately prior to the effective time of the Viper PubCo Merger (other than certain excluded shares) was canceled and automatically converted into one share of New Viper Class A common stock, par value $0.000001 per share (“New Viper Class A Common Stock”), and each share of Former Viper’s Class B common stock, par value $0.000001 per share, issued and outstanding immediately prior to the effective time of the Viper PubCo Merger was automatically canceled and converted into one share of New Viper’s Class B common stock, par value $0.000001 per share (“New Viper Class B Common Stock”). On December 23, 2025, the Company completed an internal reorganization (the “Reorganization”), pursuant to which, among other things, each outstanding OpCo Unit of Viper Energy Partners LLC, a Delaware limited liability company and Viper’s operating subsidiary (“Old OpCo”), was converted into an equivalent OpCo Unit issued by a newly-formed subsidiary of Viper, VNOM Holding Company LLC (“New OpCo”). As of December 31, 2025, Viper, through its subsidiaries, owned approximately 46.5% of the outstanding OpCo Units and was the managing member of New OpCo. Prior to March 8, 2024, the Company was a “controlled company” under the rules of the Nasdaq Stock Market LLC (the “Nasdaq Rules”). On March 8, 2024, the Company’s parent, Diamondback (as defined below), completed an underwritten public offering in which it sold 13,225,000 shares of the Company’s Class A Common Stock (the “Diamondback Offering”). Following the Diamondback Offering, Diamondback’s beneficial ownership was reduced to less than 50% of the Company’s total Common Stock outstanding. As such, the Company ceased to be a “controlled company” under the Nasdaq Rules. Prior to the Diamondback Offering, the Company’s board of directors had a majority of independent directors and a standing audit committee comprised of all independent directors, but had elected to take advantage of certain exemptions from corporate governance requirements applicable to controlled companies under the Nasdaq Rules and, until March 8, 2024, did not have a compensation committee or a committee of independent directors that selects director nominees. Effective as of March 8, 2024, the Company’s board of directors formed (i) the compensation committee for purposes of making certain executive and other compensation decisions, and (ii) the nominating and corporate governance committee for purposes of making certain nominating and corporate governance decisions, with each such committee’s rights and obligations being subject to the terms and conditions of (x) the Company’s certificate of incorporation, (y) such committee’s charter as adopted by the board, and (z) the services and secondment agreement, dated as of November 2, 2023, pursuant to which Diamondback provides personnel and general and administrative services to the Company, including the services of the executive officers and other employees (the “Services and Secondment Agreement”). Subsequent transactions completed in 2025 have resulted in Diamondback temporarily owning more than or less than 50% of the Company’s Common Stock causing changes in the Company’s status as a “controlled company” under the applicable Nasdaq Rules. While the controlled company exemptions were at times again available to the Company, the Company’s board of directors did not avail itself of these exemptions. As of December 31, 2025, Diamondback beneficially owned approximately 42.1% of the outstanding voting power of the Company’s Common Stock, on a fully diluted basis after giving effect to the outstanding TWR Class B Option (as defined and discussed in Note 4—Acquisitions and Divestitures). Conversion into Corporation Effective November 13, 2023, (the “Effective Time”), Viper Energy Partners LP converted from a publicly traded Delaware limited partnership to a Delaware corporation pursuant to a plan of conversion and changed its name from Viper Energy Partners LP to Viper Energy, Inc. Additionally, the certificate of incorporation and the bylaws of Viper Energy, Inc. became effective on the same date. This report includes the results for the Partnership prior to the Conversion and the Company following the Conversion. There are no tax impacts resulting from the Conversion as the Partnership was treated as a corporation for tax purposes. At the Effective Time, (i) each common unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class A Common Stock, (ii) each Class B unit representing limited partnership interest in the Partnership issued and outstanding immediately prior to the Effective Time was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class B Common Stock, and (iii) the general partner interest issued and outstanding immediately prior to the Effective Time (100% owned by the General Partner) was cancelled. At the Effective Time, the Company’s certificate of incorporation and bylaws generally provided its stockholders with substantially the same or greater rights and substantially the same or lesser obligations, as those that limited partners had in the Partnership Agreement. Previously, limited partners were not generally entitled to vote with respect to governance of the Partnership, except for those few matters set forth in the Partnership Agreement. Following the Conversion, except as otherwise expressly provided in the Company’s certificate of incorporation, the holders of Common Stock are entitled to vote on all matters on which stockholders of a corporation are generally entitled to vote on under the General Corporation Law of the State of Delaware, including the election of the board of directors of the Company. Diamondback continues to provide personnel and general and administrative services to the Company, including the services of the executive officers and other employees, pursuant to the Services and Secondment Agreement. In addition, for so long as Diamondback and any of its subsidiaries collectively beneficially own at least 25% of the outstanding Common Stock of the Company, (i) Diamondback will have the right to designate up to three persons to serve as directors of the Company, and (ii) the board of directors of the Company may not appoint any person other than a Diamondback seconded employee as an executive officer of the Company unless such appointment is approved, in advance, by either (x) Diamondback (which approval may not be unreasonably withheld or conditioned), or (y) the affirmative vote of the holders of at least 80% of the voting power of the capital stock of the Company. Currently, there are two Diamondback designees to the board of directors of the Company—Travis Stice and Kaes Van’t Hof. References in the accompanying consolidated financial statements and related notes thereto to “Viper” refer to (A) New Viper following the Viper PubCo Merger, (B) Former Viper prior to the Viper PubCo Merger, but after the Conversion, and (C) Viper Energy Partners LP prior to the Conversion. References to the “Company,” “our company,” “we,” “our,” “us” or like terms refer collectively to Viper and its consolidated subsidiaries. References to “shares” or per share amounts prior to the Conversion refer to common units and Class B units or per unit amounts of Viper Energy Partners LP. References to shares or per share amounts following the Conversion refer to (A) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of New Viper following the Viper PubCo Merger and (B) Class A common stock, par value $0.000001 per share and Class B common stock, par value $0.000001 per share of Former Viper prior to the Viper PubCo Merger. References to the “Operating Company” or “OpCo” refer to (A) New OpCo following the Reorganization and (B) Old OpCo prior to the Reorganization. References to “OpCo Units” are to the units representing limited liability company interests in the Operating Company. References to “Diamondback” refer collectively to Diamondback Energy, Inc. and its subsidiaries other than the Company. References to the “General Partner” refer to Viper Energy Partners GP LLC, our general partner prior to the Conversion. All references to dividends prior to the Conversion refer to distributions. Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with GAAP. All material intercompany balances and transactions are eliminated in consolidation. The Company reports its operations in one reportable segment. Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Additional Information (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2025 MBoe well reserve MBbls MMcf	Dec. 31, 2024 MBoe well MBbls MMcf	Dec. 31, 2023 MBoe well MBbls MMcf
Reserve Quantities [Line Items]
Extensions and discoveries (in MBOE) \| MBoe	62,170	24,936	25,558
Oil and gas, development well drilled, net productive, number (in wells)	1,497	1,170	904
New proved undeveloped location (in wells)	1,071	447	179
Revision of previous estimates (in MBOE) \| MBoe	(18,570)	(2,894)	138
Revisions of previous estimated quantities, due to lower commodity prices (in MBOE) \| MBoe	11,481	6,539
Proved undeveloped reserves downgrades \| MBoe	4,722	2,936	5,548
Positive (downward) revisions of previous estimated quantities due to performance revision (in MBOE) \| MBoe	(2,367)	6,580	5,688
Purchase of reserves in place (in MBOE) \| MBoe	201,291	14,941	18,977
Divestitures (in MBOE) \| MBoe	(8)	(2,138)
Proved undeveloped reserves (in MBOE) \| MBoe	89,333	32,009	35,878
Number of horizontal wells developed	1,653
Proved undeveloped reserve, horizontal wells, operated by parent, percentage	61.00%
Proved undeveloped reserves, extensions and discoveries (in MBOE) \| MBoe	46,420
Proved undeveloped reserves, purchases (in MBOE) \| MBoe	28,395
Proved undeveloped reserves, undeveloped reserves transferred to developed (in MBOE) \| MBoe	11,848
Proved undeveloped reserves, revisions (in MBOE) \| MBoe	5,643
Proved undeveloped reserves, downgrades (in MBOE) \| MBoe	4,421
Planned development period	5 years
Reserves were classified as proved developed non-producing \| reserve	0
Wolfcamp A
Reserve Quantities [Line Items]
Number of horizontal wells developed	424
Wolfcamp B
Reserve Quantities [Line Items]
Number of horizontal wells developed	415
Middle Spraberry/Jo Mill
Reserve Quantities [Line Items]
Number of horizontal wells developed	298
Lower Spraberry
Reserve Quantities [Line Items]
Number of horizontal wells developed	257
Bone Spring
Reserve Quantities [Line Items]
Number of horizontal wells developed	82
Wolfcamp D
Reserve Quantities [Line Items]
Number of horizontal wells developed	61
Dean
Reserve Quantities [Line Items]
Number of horizontal wells developed	47
Barnett
Reserve Quantities [Line Items]
Number of horizontal wells developed	46
Wolfcamp XY
Reserve Quantities [Line Items]
Number of horizontal wells developed	12
Wolfcamp C
Reserve Quantities [Line Items]
Number of horizontal wells developed	8
Upper Spraberry
Reserve Quantities [Line Items]
Number of horizontal wells developed	3
Crude Oil, Condensate, and Natural Gas Liquids (NGL)
Reserve Quantities [Line Items]
Proved undeveloped reserve (volume) \| MBbls	46,170	17,543	20,860
Natural Gas
Reserve Quantities [Line Items]
Proved undeveloped reserve (volume) \| MMcf	123,983	39,353	42,116
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved undeveloped reserve (volume) \| MBbls	22,499	7,907	7,999

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Standardized measure of discounted future net cash flows at the beginning of the period	$ 3,320	$ 3,187	$ 3,454
Purchase of minerals in place	3,738	355	474
Divestiture of reserves	0	(51)	0
Sales of oil and natural gas, net of production costs	(1,252)	(793)	(667)
Extensions and discoveries	1,401	640	627
Net changes in prices and production costs	(279)	(438)	(1,405)
Revisions of previous quantity estimates	(374)	(85)	3
Net changes in income taxes	(370)	70	212
Accretion of discount	368	374	428
Net changes in timing of production and other	95	61	61
Standardized measure of discounted future net cash flows at the end of the period	$ 6,647	$ 3,320	$ 3,187

DEBT

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

DEBT

Long-term debt consisted of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
5.375% Senior Notes due 2027	$	—	$	430
4.900% Senior Notes due 2030	500		—
7.375% Senior Notes due 2031	—		400
5.700% Senior Notes due 2035	1,100		—
Term Loan	500		—
Revolving credit facility	105		261
Unamortized debt issuance costs	(15)		(6)
Unamortized discount costs	(4)		(2)
Total long-term debt	$	2,186	$	1,083

2025 Revolving Credit Facility

On June 12, 2025, Former Viper, as guarantor, entered into a credit agreement with the Operating Company, as borrower, and Wells Fargo, as the administrative agent (the “2025 Revolving Credit Facility”), which among other things, provides the borrower with a senior unsecured revolving credit facility with a commitment of $1.5 billion, a swingline commitment of up to $50 million and a letter of credit commitment of $5 million. The 2025 Revolving Credit Facility has a maturity date of June 12, 2030, with the ability to request three extensions of the maturity date by one year. The 2025 Revolving Credit Facility was previously guaranteed by certain subsidiaries of the borrower, and upon completion of the Sitio Acquisition, those subsidiary guarantees were released and New Viper and Former Viper became co-guarantors. The 2025 Revolving Credit Facility replaced the borrower’s previous revolving credit facility, dated July 20, 2018, among the Company, the borrower and Wells Fargo as amended, restated, amended and restated, supplemented or otherwise modified prior to June 12, 2025. As of December 31, 2025, there was $105 million in outstanding borrowings and $1.4 billion available for future borrowings under the 2025 Revolving Credit Facility. For the years ended December 31, 2025, 2024 and 2023, the weighted average interest rates on borrowings under the borrower’s respective revolving credit facilities were 6.02%, 7.34%, and 7.41%, respectively.

Borrowings under the 2025 Revolving Credit Facility bear interest at a per annum rate elected by the borrower that is equal to term SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate loans and from 1.125% to 2.000% per annum in the case of term SOFR loans, in each case based on the pricing level. Further, the commitment fee ranges from 0.125% to 0.325% per annum on the average daily unused portion of the commitment, again based on the pricing level. The pricing level depends on the rating of the Company’s long-term senior unsecured debt by certain ratings agencies.

The 2025 Revolving Credit Facility contains a financial covenant that requires the Company to maintain a Total Net Debt to Capitalization Ratio (as defined in the 2025 Revolving Credit Facility) of no more than 65%. As of December 31, 2025, the borrower was in compliance with all financial maintenance covenants under the 2025 Revolving Credit Facility.

On December 23, 2025, Old OpCo converted its legal form (the “OpCo Conversion”), in accordance with the applicable laws of the State of Delaware, to a Delaware limited partnership named Viper Energy Partners LP (“Viper LP”), which thereupon became the borrower with respect to the 2025 Revolving Credit Facility.

Term Loan

On July 23, 2025, in connection with the Sitio Acquisition, Former Viper, as guarantor, entered into a term loan credit agreement with the Operating Company, as borrower, and Goldman Sachs Bank USA, as administrative agent, (the “Term Loan”).

The Term Loan provided the Company with the ability to borrow up to $500 million on a senior unsecured basis to fund a portion of the retirement of Sitio’s net debt, in connection with the Sitio Acquisition. On August 19, 2025, the date of closing of the Sitio Acquisition, the Term Loan was fully drawn in a single borrowing. Any then-outstanding amounts will mature and be payable in full on the second anniversary of the initial funding date. In connection with the closing of the Sitio Acquisition, New Viper became a co-guarantor of the Term Loan. During the year ended December 31, 2025, the weighted average interest rate on borrowings under the Term Loan was 5.72%.

Borrowings under the Term Loan bear interest at a per annum rate elected by the borrower that is equal to SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. The applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate loans and from 1.250% to 2.125% per annum in the case of term SOFR loans, in each case based on the pricing level. The pricing level depends on the rating of the Company’s long-term senior unsecured debt by certain ratings agencies. In addition, the fee on undrawn commitments is equal to 0.20% per annum on the aggregate principal amount of such commitments.

Following the OpCo Conversion, Viper LP became the borrower under the Term Loan.

Guaranteed Senior Notes Offering

On July 23, 2025, the Operating Company, as issuer, and Former Viper, as guarantor, issued $1.6 billion in aggregate principal amount of the Guaranteed Senior Notes consisting of (i) $500 million aggregate principal amount of 4.900% Senior Notes due August 1, 2030, (the “2030 Notes”), and (ii) $1.1 billion aggregate principal amount of 5.700% Senior Notes due August 1, 2035, (the “2035 Notes”). The Company received net proceeds of approximately $1.58 billion, after underwriters’ discounts and transaction costs. Interest on the Guaranteed Senior Notes is payable semi-annually in February and August of each year, beginning on February 1, 2026. Concurrently, the Company used approximately $824 million of the proceeds to redeem approximately $780 million in aggregate principal amounts of the Company’s outstanding Notes, including accrued interest due and applicable redemption premiums. Following the closing of the Sitio Acquisition, the Company used the remaining proceeds from the issuance of the Guaranteed Senior Notes to (i) retire Sitio’s 7.875% senior notes due 2028, (ii) partially repay borrowings under Sitio’s revolving credit facility, (iii) pay fees, costs and expenses related to the redemption or repayment of such debt, and (iv) for general corporate purposes.

The Guaranteed Senior Notes (i) are senior unsecured obligations and are fully and unconditionally guaranteed by Former Viper, and, following the closing of the Sitio Acquisition, also by New Viper, (ii) are senior in right of payment to any of the Company’s future subordinated indebtedness, and (iii) rank equal in right of payment with all of the Company’s existing and future senior indebtedness. The Guaranteed Senior Notes have been registered under the Securities Act.

Following the OpCo Conversion, Viper LP became the issuer with respect to the Guaranteed Senior Notes.

Retirement of Notes

During the second quarter of 2025, the Company opportunistically repurchased principal amounts of $50 million of its 5.375% Senior Notes due 2027 (the “2027 Notes”) in open market transactions for total cash consideration of $50 million, at an average of 99.7% of par value, resulting in an immaterial gain on extinguishment of debt for the year ended December 31, 2025.

On July 23, 2025, using proceeds from the issuance of the Guaranteed Senior Notes, the Company (i) redeemed all of its outstanding 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”), which were issued in October 2023 to partially fund the cash portion of the GRP Acquisition, for total cash consideration of approximately $434 million including the applicable redemption premium of 106.767% of par and accrued and unpaid interest up to, but not including, the redemption date, and (ii) deposited approximately $390 million to redeem all of its outstanding 2027 Notes on November 1, 2025, for total cash consideration, including payment of interest due to, but not including, the redemption date at a redemption price equal to 100% of the principal amount of the 2027 Notes. The redemption of the 2031 Notes resulted in a loss on extinguishment of debt of $32 million.

Interest Expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2025, 2024 and 2023:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Interest expense	$	103	$	74	$	48
Other fees and expenses	3		2		1
Less: interest income	10		2		2


Interest expense, net	$	96	$	74	$	47

FAIR VALUE MEASUREMENTS - Schedule of Fair Value of Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	$ 2,186	$ 1,083
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	$ 2,233	$ 1,105

- Definition

The fair value amount of long-term debt whether such amount is presented as a separate caption or as a parenthetical disclosure. Additionally, this element may be used in connection with the fair value disclosures required in the footnote disclosures to the financial statements. The element may be used in both the balance sheet and disclosure in the same submission.

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Reference 1: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 10: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 820
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

+ Details

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

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,
	2025		2024
	(In millions)
Oil and natural gas interests:
Proved	$	9,746	$	3,533
Unproved	4,910		2,180
Total oil and natural gas interests	14,656		5,713
Accumulated depletion	(1,567)		(961)
Accumulated impairment	(888)		(120)
Net oil and natural gas interests capitalized	$	12,201	$	4,632

Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil and natural gas property acquisition activities are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Acquisition costs:
Proved properties	$	4,976	$	341	$	403
Unproved properties	3,968		830		758
Total	$	8,944	$	1,171	$	1,161

Results of Operations from Oil and Natural Gas Producing Activities

Substantially all of the Company’s producing activities are from oil and natural gas activities and are included in the “—Consolidated Statements of Operations.”

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by the Company’s internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as of December 31, 2025, 2024 and 2023. The reserve estimates represent the Company’s net revenue interest in the Company’s properties. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon SEC Prices for the periods ended December 31, 2025, 2024 and 2023, respectively. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. All of the Company’s proved reserves included in the reserve reports are located in the continental United States. Although the estimates are believed to be reasonable, actual future production, cash flows, taxes and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The following table presents changes in estimated proved reserves, which were prepared in accordance with the rules and regulations of the SEC:


	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBOE)(1)
Proved Developed and Undeveloped Reserves:
As of December 31, 2022	79,004	209,964	34,902	148,900
Purchase of reserves in place	10,469	27,011	4,006	18,977
Extensions and discoveries	13,636	34,632	6,150	25,558
Revisions of previous estimates	(5,178)	11,101	3,466	138

Production	(8,028)	(19,130)	(3,108)	(14,324)
As of December 31, 2023	89,903	263,578	45,416	179,249
Purchase of reserves in place	7,891	20,310	3,665	14,941
Extensions and discoveries	13,099	33,498	6,254	24,936
Revisions of previous estimates	(6,472)	4,449	2,837	(2,894)
Divestitures	(919)	(4,605)	(451)	(2,138)
Production	(9,939)	(24,606)	(4,181)	(18,221)
As of December 31, 2024	93,563	292,624	53,540	195,873
Purchase of reserves in place	90,168	336,127	55,102	201,291
Extensions and discoveries	31,305	90,973	15,702	62,170
Revisions of previous estimates	(3,951)	(31,751)	(9,328)	(18,570)
Divestitures	(4)	(12)	(2)	(8)
Production	(17,875)	(51,676)	(8,233)	(34,721)
As of December 31, 2025	193,206	636,285	106,781	406,035

Proved Developed Reserves:
December 31, 2023	69,043	221,462	37,417	143,371
December 31, 2024	76,020	253,271	45,633	163,865
December 31, 2025	147,036	512,302	84,282	316,702

Proved Undeveloped Reserves:
December 31, 2023	20,860	42,116	7,999	35,878
December 31, 2024	17,543	39,353	7,907	32,009
December 31, 2025	46,170	123,983	22,499	89,333

(1)Includes total proved reserves of 219,259 MBOE, 94,019 MBOE, 91,417 MBOE and 81,895 MBOE as of December 31, 2025, 2024, 2023 and 2022, respectively, attributable to a non-controlling interest in the Operating Company.

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.

During the year ended December 31, 2025, the Company’s total extensions and discoveries of 62,170 MBOE resulted primarily from the drilling of 1,497 new wells and from 1,071 new proved undeveloped locations added. The Company’s total downward revisions of previous estimated quantities of 18,570 MBOE were primarily attributable to negative revisions of (i) 11,481 MBOE associated with lower commodity prices, (ii) 4,722 MBOE due to PUD downgrades, and (iii) 2,367 MBOE primarily attributable to performance revisions. Total purchases of reserves in place of 201,291 MBOE resulted primarily from the Sitio Acquisition, the 2025 Drop Down, the Morita Ranches Acquisition and other acquisitions of certain mineral and royalty interests.

During the year ended December 31, 2024, the Company’s total extensions and discoveries of 24,936 MBOE resulted primarily from the drilling of 1,170 new wells and from 447 new proved undeveloped locations added. The Company’s total downward revisions of previous estimated quantities of 2,894 MBOE were primarily attributable to negative revisions of (i) 6,539 MBOE associated with lower commodity prices, and (ii) 2,936 MBOE due primarily to PUD downgrades partially offset by positive revisions of 6,580 MBOE primarily attributable to performance revisions. Total purchases of reserves in place of 14,941 MBOE resulted primarily from the Tumbleweed Acquisitions and other acquisitions of certain mineral and royalty interests. Divestitures of 2,138 MBOE related primarily to non-core mineral and royalty interests.

During the year ended December 31, 2023, the Company’s total extensions and discoveries of 25,558 MBOE resulted primarily from the drilling of 904 new wells and from 179 new proved undeveloped locations added. The Company’s total positive revisions of previous estimated quantities of 138 MBOE consist of positive revisions of 5,688 MBOE primarily attributable to performance revisions which were largely offset by PUD downgrades of 5,548 MBOE. Total purchases of reserves in place of 18,977 MBOE resulted primarily from the GRP Acquisition and other acquisitions of certain mineral and royalty interests.

Proved Undeveloped Reserves

As of December 31, 2025, the Company’s PUD reserves totaled 46,170 MBbls of oil, 123,983 MMcf of natural gas and 22,499 MBbls of natural gas liquids, for a total of 89,333 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. The Company’s PUD reserves were from 1,653 horizontal wells, 61% of which are operated by Diamondback. Of the horizontal locations, 424 are Wolfcamp A wells, 415 are Wolfcamp B wells, 298 are Middle Spraberry/Jo Mill wells, 257 are Lower Spraberry wells, 82 are Bone Spring wells, 61 are Wolfcamp D wells, 47 are Dean wells, 46 are Barnett wells, 12 are Wolfcamp XY wells, eight are Wolfcamp C wells and three are Upper Spraberry wells.

The following table includes the changes in PUD reserves for 2025:


			MBOE
Beginning proved undeveloped reserves at December 31, 2024			32,009
Undeveloped reserves transferred to developed			(11,848)
Revisions			(5,643)
Purchases			28,395

Extensions and discoveries			46,420
Ending proved undeveloped reserves at December 31, 2025			89,333

The increase in PUD reserves was primarily attributable to positive additions of 46,420 MBOE, primarily from 1,071 new horizontal well locations attributable to extensions resulting from strategic drilling of wells to delineate the Company’s acreage position and acquisitions of 28,395 MBOE. These increases in PUD reserves were partially offset by the conversion of 11,848 MBOE of PUD reserves into proved developed reserves and downward revisions of 5,643 MBOE primarily attributable to PUD downgrades of 4,421 MBOE.

All of the Company’s PUD drilling locations are scheduled to be drilled within five years from the date they were initially recorded. As of December 31, 2025, none of the Company’s total proved reserves were classified as proved developed non-producing.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is based on SEC Prices. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future due to development and production of the reserves not occurring in the periods assumed, as well as actual prices realized and actual costs incurred varying significantly from those used in the estimates of proved reserves.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2025, 2024 and 2023:


	December 31,
	2025		2024		2023
	(In millions)
Future cash inflows	$	15,377	$	8,323	$	8,494
Future production taxes	(1,080)		(578)		(594)
Future income tax expense	(1,389)		(749)		(935)
Future net cash flows	12,908		6,996		6,965
10% discount to reflect timing of cash flows	(6,261)		(3,676)		(3,778)
Standardized measure of discounted future net cash flows(1)	$	6,647	$	3,320	$	3,187

(1)Includes a 54%, 48% and 51% non-controlling interest in the Operating Company at December 31, 2025, 2024 and 2023, respectively.

The following table presents the SEC Prices as adjusted for differentials and contractual arrangements utilized in the computation of future cash inflows:


	December 31,
	2025		2024		2023


Oil (per Bbl)	$	64.80	$	75.61	$	77.93
Natural gas (per Mcf)	$	1.31	$	0.49	$	1.54
Natural gas liquids (per Bbl)	$	18.95	$	20.62	$	23.79

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	3,320	$	3,187	$	3,454
Purchase of minerals in place	3,738		355		474
Divestiture of reserves	—		(51)		—
Sales of oil and natural gas, net of production costs	(1,252)		(793)		(667)
Extensions and discoveries	1,401		640		627
Net changes in prices and production costs	(279)		(438)		(1,405)
Revisions of previous quantity estimates	(374)		(85)		3
Net changes in income taxes	(370)		70		212
Accretion of discount	368		374		428
Net changes in timing of production and other	95		61		61
Standardized measure of discounted future net cash flows at the end of the period	$	6,647	$	3,320	$	3,187

- Definition

The entire disclosure for oil- and gas-producing activities considered to be supplementary information. Includes, but is not limited to, proved reserve quantity, cost incurred and capitalized, result of operation, standardized measure, and change in standardized measure of discounted future cash flow.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478688/932-270-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-10

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 12.A.3.e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477759/932-235-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section S50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479097/932-235-S50-3

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Subparagraph (c)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-8

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/932/tableOfContent

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 1C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-1C

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 36
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-36

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Subparagraph (c)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-8

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 932
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477215/932-235-50-5

+ Details

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved properties	$ 4,976	$ 341	$ 403
Unproved properties	3,968	830	758
Total	$ 8,944	$ 1,171	$ 1,161

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Prepaid Expenses and Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Accounting Policies [Abstract]
Derivative instruments	$ 28	$ 18
Prepaid expenses	13	11
Other	9	2
Total prepaid expenses and other current assets	$ 50	$ 31

OIL AND NATURAL GAS INTERESTS - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) a	Dec. 31, 2024 USD ($) a	Dec. 31, 2023 USD ($)
Oil and Gas, Acreage [Line Items]
Net royalty acres \| a	96,003	35,671
Impairment \| $	$ 768	$ 0	$ 0
Minimum
Oil and Gas, Acreage [Line Items]
Anticipated timing of cost inclusion in amortization calculation	9 years
Maximum
Oil and Gas, Acreage [Line Items]
Anticipated timing of cost inclusion in amortization calculation	12 years

EARNINGS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Earnings Per Share [Abstract]
Net income (loss) attributable to the period	$ (68)	$ 359	$ 200
Less: net income (loss) allocated to participating securities	1	0	0
Net income (loss) attributable to common stockholders	$ (69)	$ 359	$ 200
Basic weighted average common shares outstanding (in shares)	142,530,000	93,932,000	74,176,000
Effect of dilutive securities:
Potential common shares issuable (in shares)	0	0	0
Diluted weighted average common shares outstanding (in shares)	142,530,000	93,932,000	74,176,000
Net income (loss) per common share, basic (usd per share)	$ (0.48)	$ 3.82	$ 2.69
Net income (loss) per common share, diluted (usd per share)	$ (0.48)	$ 3.82	$ 2.69
Antidilutive securities, restricted stock units (in shares)	110,342	0	0

ACQUISITIONS AND DIVESTITURES	12 Months Ended
ACQUISITIONS AND DIVESTITURES	Dec. 31, 2025
Business Combinations And Divestitures [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 2025 Activity Sitio Acquisition On August 19, 2025, the Company completed a series of transactions in which New Viper acquired Sitio Royalties Corp. (“Sitio”), Sitio OpCo and their respective subsidiaries, pursuant to the Agreement and Plan of Merger, dated June 2, 2025, by and among Former Viper, the Operating Company, Sitio, Sitio OpCo, New Viper, Cobra Merger Sub, Inc. and Scorpion Merger Sub, Inc. (the “Sitio Acquisition”). The Sitio Acquisition was an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The Company funded the retirement of Sitio’s net debt through a combination of cash on hand, proceeds from the issuance of the Guaranteed Senior Notes and borrowings under the Term Loan (as defined and discussed in Note 6—Debt). Equity consideration for the Sitio Acquisition consisted of the right for Sitio and Sitio OpCo’s former equity holders to receive (i) 0.4855 shares of New Viper Class A Common Stock, for each share of Sitio Class A common stock, par value $0.0001 per share, and (ii) 0.4855 OpCo Units, along with a corresponding amount of New Viper Class B Common Stock, for each unit representing limited partnership interests of Sitio OpCo, subject to certain exclusions. The OpCo Units and New Viper Class B Common Stock issued in the Sitio Acquisition are exchangeable from time to time for shares of New Viper Class A Common Stock (that is, one OpCo Unit and one share of Class B Common Stock, together, are exchangeable for one share of Class A Common Stock). Each share of Class C common stock, par value $0.0001 per share, of Sitio was automatically canceled in the transaction for no consideration and ceased to exist upon closing of the Sitio Acquisition. The shares of common stock of Former Viper and Sitio were delisted from the Nasdaq and their respective reporting obligations under the Exchange Act were terminated. As part of the Sitio Acquisition, New Viper issued 38,536,236 shares of Class A Common Stock, 35,619,951 shares of Class B Common Stock and 35,619,951 OpCo Units. In addition, at the closing of the Sitio Acquisition, the Company entered into a registration rights agreement with certain of Sitio OpCo’s former equity holders, pursuant to which such equity holders received certain demand registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by them in exchange for OpCo Units and shares of the Company’s Class B Common Stock. The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres. See Note 13—Subsequent Events for discussion of divestiture of the non-Permian acreage in 2026. The Sitio Acquisition was accounted for as an asset acquisition in accordance with ASC 805. 2025 Drop Down On May 1, 2025, the Company acquired all of the issued and outstanding equity interests in 1979 Royalties, LP and 1979 Royalties GP, LLC from Endeavor Energy Resources, LP (“Endeavor”), each a seller party and a subsidiary of Diamondback, pursuant to a definitive equity purchase agreement for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69,626,640 OpCo Units and an equivalent number of shares of the Company’s Class B Common Stock (the “2025 Drop Down”). The OpCo Units and the Class B Common Stock issued in the 2025 Drop Down, as well as the OpCo Units and Class B Common Stock otherwise beneficially owned by Diamondback, are exchangeable from time to time for shares of the Company’s Class A Common Stock (that is, one OpCo Unit and one share of Class B Common Stock, together, are exchangeable for one share of Class A Common Stock). The shares of Class A Common Stock that may be issued to Diamondback and/or its subsidiaries upon exchange of their OpCo Units and shares of Class B Common Stock, including those OpCo Units and shares of Class B Common Stock issued at the closing of the 2025 Drop Down, are subject to the Company’s existing registration rights agreement with Diamondback, dated as of November 13, 2023, previously filed by the Company with the SEC. The mineral and royalty interests acquired in the 2025 Drop Down represent approximately 24,446 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback, and have an average net royalty interest of approximately 2.2% and then-current oil production of approximately 17,097 BO/d (the “Endeavor Mineral and Royalty Interests”). The Endeavor Mineral and Royalty Interests include interests in horizontal wells comprised of 5,574 gross proved developed production wells (of which approximately 32% are operated by Diamondback), 116 gross completed wells and 394 gross drilled but uncompleted wells, all of which are principally concentrated in the Midland Basin, with the balance located primarily in the Delaware and Williston Basins. The 2025 Drop Down was approved by (i) the Company’s audit committee comprised of all independent directors and the full board of directors, in each case on January 30, 2025, and (ii) the majority of the Company’s stockholders, other than Diamondback and its subsidiaries, at the special meeting of the Company’s stockholders held on May 1, 2025, as required under the Nasdaq Rules. The Company funded the cash consideration for the 2025 Drop Down with a portion of the proceeds from the 2025 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity) and borrowings under our previous revolving credit facility. The 2025 Drop Down was accounted for as a transaction between entities under common control, with the Endeavor Mineral and Royalty Interests recorded at Endeavor’s historical carrying value in the Company’s consolidated balance sheet. Morita Ranches Acquisition On February 14, 2025, the Company completed an acquisition of certain mineral and royalty interests located in Howard County, Texas from Morita Ranches Minerals, LLC (“Morita Ranches”) (the “Morita Ranches Acquisition”) pursuant to a definitive purchase and sale agreement for consideration consisting of approximately (i) $208 million in cash, and (ii) 2,400,297 OpCo Units together with an equal number of shares of the Company’s Class B Common Stock issued to certain affiliate designees of Morita Ranches (the “Morita Ranches Equity Recipients”), including customary transaction costs and post-closing adjustments. At the closing of the Morita Ranches Acquisition, the Morita Ranches Equity Recipients (i) became parties to the Third Amended and Restated Limited Liability Agreement of the Operating Company, dated as of October 1, 2024, as amended, and (ii) entered into an Exchange Agreement with the Company and the Operating Company to provide for the right to exchange the OpCo Units and shares of the Company’s Class B Common Stock acquired by the Morita Ranches Equity Recipients at the closing of the Morita Ranches Acquisition for an equal number of shares of the Company’s Class A Common Stock. In addition, at the closing of the Morita Ranches Acquisition, the Company entered into a registration rights agreement pursuant to which the Morita Ranches Equity Recipients received certain demand and piggyback registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by them in exchange for OpCo Units and shares of the Company’s Class B Common Stock. The mineral and royalty interests included in the Morita Ranches Acquisition represent approximately 1,691 net royalty acres in the Permian Basin, 75% of which are operated by Diamondback, and have an average net royalty interest of approximately 10.9%. The Company funded the cash consideration for the Morita Ranches Acquisition with proceeds from the 2025 Equity Offering. The Morita Ranches Acquisition was accounted for as an asset acquisition in accordance with ASC 805. Other Acquisitions During the year ended December 31, 2025, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 515 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $140 million, including customary closing adjustments. In the second half of 2025, the Company acquired, in individually insignificant transactions from Diamondback E&P LLC, mineral and royalty interests representing 80 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $2 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our revolving credit facility. 2024 Activity Acquisitions Tumbleweed Acquisitions In September and October of 2024, the Company completed a series of related acquisitions including the TWR Acquisition, the Q Acquisition and the M Acquisition (collectively the “Tumbleweed Acquisitions”), each as defined and discussed below. TWR Acquisition On October 1, 2024, the Company acquired all of the issued and outstanding equity interests in TWR IV, LLC and TWR IV SellCo, LLC from TWR IV and TWR IV SellCo Parent, LLC (the “TWR Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $464 million in cash, including transaction costs and certain customary post-closing adjustments, (ii) 10,093,670 OpCo Units to TWR IV, (iii) an option granted to TWR IV to acquire up to 10,093,670 shares of the Company’s Class B Common Stock (the “TWR Class B Option”), and (iv) contingent cash consideration of $16 million paid in January 2026 (the “TWR Contingent Liability”) based on the average price of WTI sweet crude oil prompt month futures contracts for the calendar year 2025 (the “WTI 2025 Average”), which was between $60.00 and $65.00. Additionally, at the closing of the TWR Acquisition, the Company assumed a royalty income receivable of approximately $24 million. TWR IV can exchange some or all of its OpCo Units for an equal number of shares of the Company’s Class A Common Stock and any OpCo Units so exchanged will reduce the number of shares of Class B Common Stock subject to the TWR Class B Option. In addition, at the closing of the TWR Acquisition, the Company entered into a registration rights agreement with TWR IV, pursuant to which TWR IV received certain demand and piggyback registration rights with respect to the shares of the Company’s Class A Common Stock that may be acquired by TWR IV in exchange for OpCo Units. The mineral and royalty interests acquired in the TWR Acquisition represent approximately 3,067 net royalty acres located primarily in the Permian Basin. The Company funded the cash consideration for the TWR Acquisition through a combination of cash on hand, borrowings under our previous revolving credit facility and proceeds from the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity). Q Acquisition On September 3, 2024, the Company acquired all of the issued and outstanding equity interests in Tumbleweed-Q Royalties, LLC (the “Q Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $114 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of $2 million paid in January 2026 (the “Q Contingent Liability”) based on the WTI 2025 Average, which was between $60.00 and $65.00. The mineral and royalty interests acquired in the Q Acquisition represent approximately 406 net royalty acres located primarily in the Permian Basin. The cash consideration for the Q Acquisition was funded through a combination of cash on hand and borrowings under our previous revolving credit facility. M Acquisition On September 3, 2024, the Company acquired all of the issued and outstanding equity interests in MC TWR Royalties, LP and MC TWR Intermediate, LLC (the “M Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $76 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of $2 million paid in January 2026 (the “M Contingent Liability”) based on the WTI 2025 Average, which was between $60.00 and $65.00. The mineral and royalty interests acquired in the M Acquisition represent approximately 267 net royalty acres located primarily in the Permian Basin. The cash consideration for the M Acquisition was funded through a combination of cash on hand and borrowings under our previous revolving credit facility. The Q Contingent Liability, the M Contingent Liability and the TWR Contingent Liability are collectively referred to as the “2026 WTI Contingent Liability.” Other Acquisitions In addition to the acquisitions discussed above, during the year ended December 31, 2024, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 261 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $54 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our previous revolving credit facility. Divestiture In the second quarter of 2024, the Company divested all of its non-Permian assets for a purchase price of approximately $87 million, including transaction costs and customary post-closing adjustments. The divested properties consisted of approximately 2,713 net royalty acres with current production of approximately 450 BO/d. The Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale. 2023 Activity Acquisitions GRP Acquisition On November 1, 2023, the Company acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP, affiliates of Warwick Capital Partners and GRP Energy Capital (collectively, “GRP”), pursuant to a definitive purchase and sale agreement for 9,018,760 common units and $747 million in cash, including transaction costs and certain customary post-closing adjustments (the “GRP Acquisition”). The mineral and royalty interests acquired in the GRP Acquisition represent approximately 4,600 net royalty acres in the Permian Basin, and approximately 2,700 additional net royalty acres in other major basins. The cash consideration for the GRP Acquisition was funded through a combination of cash on hand and held in escrow, borrowings under our previous revolving credit facility, proceeds from the 2031 Notes (as defined and discussed in Note 6—Debt) and proceeds from the $200 million common unit issuance to Diamondback discussed further in Note 7—Stockholders’ Equity. 2023 Drop Down On March 8, 2023, the Company acquired certain mineral and royalty interests from subsidiaries of Diamondback for approximately $75 million in cash, including customary closing adjustments for net title benefits (the “2023 Drop Down”). The mineral and royalty interests acquired in the 2023 Drop Down represented approximately 660 net royalty acres in Ward County, Texas in the Southern Delaware Basin, 100% of which were operated by Diamondback, and had an average net royalty interest of approximately 7.2% and then-current production of approximately 300 BO/d. The Company funded the 2023 Drop Down through a combination of cash on hand and borrowings under our previous revolving credit facility. The 2023 Drop Down was accounted for as a transaction between entities under common control with the acquired properties recorded at Diamondback’s historical carrying value in the Company’s consolidated balance sheet. The historical carrying value of the properties approximated the 2023 Drop Down purchase price. Other Acquisitions Additionally during the year ended December 31, 2023, the Company acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 286 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $70 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under our previous revolving credit facility.

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2025

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets Measured on Recurring and Nonrecurring Basis

The following tables provide (i) the consolidated balance sheet classification where the Company’s commodity derivative instrument assets and liabilities and 2026 WTI Contingent Liability are recorded, (ii) fair value measurement information, (iii) the gross amounts of recognized assets and liabilities, (iv) the amounts offset under master netting arrangements with counterparties, and (v) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2025, and December 31, 2024:


	As of December 31, 2025
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	37	$	—	$	37	$	(9)	$	28


Liabilities:
Other current liabilities	$	—	$	9	$	—	$	9	$	(9)	$	—
Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	20	$	—	$	20	$	—	$	20
Other long-term liabilities	$	—	$	7	$	—	$	7	$	—	$	7


	As of December 31, 2024
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	24	$	—	$	24	$	(6)	$	18



Liabilities:
Other current liabilities	$	—	$	8	$	—	$	8	$	(6)	$	2

Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	30	$	—	$	30	$	—	$	30

Schedule of Offsetting Liabilities


	As of December 31, 2025
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	37	$	—	$	37	$	(9)	$	28


Liabilities:
Other current liabilities	$	—	$	9	$	—	$	9	$	(9)	$	—
Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	20	$	—	$	20	$	—	$	20
Other long-term liabilities	$	—	$	7	$	—	$	7	$	—	$	7


	As of December 31, 2024
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	24	$	—	$	24	$	(6)	$	18



Liabilities:
Other current liabilities	$	—	$	8	$	—	$	8	$	(6)	$	2

Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	30	$	—	$	30	$	—	$	30

Schedule of Offsetting Assets


	As of December 31, 2025
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	37	$	—	$	37	$	(9)	$	28


Liabilities:
Other current liabilities	$	—	$	9	$	—	$	9	$	(9)	$	—
Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	20	$	—	$	20	$	—	$	20
Other long-term liabilities	$	—	$	7	$	—	$	7	$	—	$	7


	As of December 31, 2024
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	24	$	—	$	24	$	(6)	$	18



Liabilities:
Other current liabilities	$	—	$	8	$	—	$	8	$	(6)	$	2

Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	30	$	—	$	30	$	—	$	30

Schedule of Fair Value Consolidated Balance Sheets

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:


	December 31, 2025				December 31, 2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
Debt	$	2,186	$	2,233	$	1,083	$	1,105

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Debt Issuance Costs (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Accounting Policies [Abstract]
Debt issuance costs, net of accumulated amortizations	$ 21	$ 18
Debit issuance costs, accumulated amortization	$ 13	$ 11

DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2025, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.


					Swaps	Collars		Puts
Settlement Month	Settlement Year	Type of Contract	Bbls/MMBtu Per Day	Index	Weighted Average Differential	Weighted Average Floor Price	Weighted Average Ceiling Price	Strike Price	Deferred Premium
OIL
Jan. - Mar.	2026	Puts	40,000	WTI Cushing	$—	$—	$—	$51.75	$(1.56)
Apr. - Jun.	2026	Puts	20,000	WTI Cushing	$—	$—	$—	$48.13	$(1.35)
NATURAL GAS
Jan. - Dec.	2026	Basis Swaps	80,000	Waha Hub	$(1.61)	$—	$—	$—	$—
Jan. - Dec.	2027	Basis Swaps	40,000	Waha Hub	$(1.40)	$—	$—	$—	$—
Jan. - Dec.	2026	Costless Collar	60,000	Henry Hub	$—	$2.75	$6.64	$—	$—

Schedule of Derivative Contract Gains and Losses included in the Consolidated Statements of Operations

The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts	$	31	$	15	$	(26)
2026 WTI Contingent Liability	10		(4)		—
Treasury locks	3		—		—
Total	$	44	$	11	$	(26)

Net cash receipts (payments) on derivatives:
Commodity contracts	$	27	$	(3)	$	(13)

Treasury locks	3		—		—
Total	$	30	$	(3)	$	(13)

INCOME TAXES - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 5	$ 0
Investment in the Operating Company	28	185
Total deferred tax assets	33	185
Valuation allowance	0	0
Net deferred tax assets	33	185
Net deferred tax assets (liabilities)	$ 33	$ 185

Consolidated Statements of Stockholders’ Equity - USD ($)
$ in Millions

Total

Common Class A And B

Common Class A

Common Class B

Operating Company Units

General Partner

Common Units

Limited Partners

Class B Units

Limited Partners

Common Stock

Common Class A

Common Stock

Common Class B

Additional Paid-in Capital

Retained Earnings (Accumulated Deficit)

Non-Controlling Interest

Operating Company Units

Beginning balance (in shares) at Dec. 31, 2022

73,230,000

90,710,000

Beginning balance at Dec. 31, 2022

$ 1

$ 689

$ 1

Increase (Decrease) in Partners' Capital [Roll Forward]

Conversion of Viper Energy Partners LP Partnership Units to Viper Energy Inc. Shares of Common Stock (in shares)

(78,126,000)

(90,710,000)

Conversion of Viper Energy Partners LP Partnership Units to Viper Energy Inc. Shares of Common Stock

$ (937)

$ (1)

Conversion of Viper Energy Partners LP Partnership Units to Viper Energy Inc. Shares of Common Stock (in shares)

^[1]

78,126,000

90,710,000

Conversion of Viper Energy Partners LP Partnership Units to Viper Energy Inc. Shares of Common Stock

$ 0

$ 938

Liquidation of General Partner

(2)

(1)

Common shares/units issued to related party (in shares)

7,215,000

Common shares/units issued to related party

200

$ 200

Equity-based compensation

$ 1

Vesting of restricted stock units (in shares)

73,000

Dividends/distributions to shareholders

(129)

$ (84)

$ (45)

Dividends/distributions to Diamondback

(196)

(1)

(4)

$ (191)

Change in ownership of consolidated subsidiaries, net

$ 31

(133)

102

Repurchases of shares of Class A Common Stock under repurchase program (in shares)

(2,392,000)

(1,000,000)

^[1]

Repurchases as part of share/unit buyback

(95)

$ (67)

(28)

Net income (loss)

200

Net income (loss)

501

$ 168

301

Ending balance (in shares) at Dec. 31, 2023

Ending balance at Dec. 31, 2023

$ 0

Beginning balance (in shares) at Dec. 31, 2022

^[1]

Beginning balance at Dec. 31, 2022

2,322

1,631

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Common shares/units issued for acquisition (in shares)

^[1]

9,018,000

Common shares/units issued for acquisition

255

Common shares/units issued to related party

200

Equity-based compensation

$ 1

Net proceeds from the issuance of Common Stock (in shares)

73,000

Change in ownership of consolidated subsidiaries, net

$ 31

(133)

102

Repurchases of shares of Class A Common Stock under repurchase program (in shares)

(2,392,000)

(1,000,000)

^[1]

Repurchases of shares of Class A Common Stock under repurchase program

(95)

$ (67)

(28)

Net income (loss)

501

$ 168

301

Ending balance (in shares) at Dec. 31, 2023

^[1],[2]

86,144,000

90,710,000

Ending balance at Dec. 31, 2023

2,857

1,031

(17)

1,843

Increase (Decrease) in Partners' Capital [Roll Forward]

Equity-based compensation

Change in ownership of consolidated subsidiaries, net

(20)

(79)

Net income (loss)

359

Net income (loss)

604

359

245

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Common shares/units issued for acquisition (in shares)

^[2]

5,279,000

(5,279,000)

Common shares/units issued for acquisition

$ 468

Common shares issued to related party (in shares)

^[2]

11,500,000

Common shares issued to related party

476

Equity-based compensation

Issuance of shares upon vesting of equity awards (in shares)

^[2]

54,000

Dividends to stockholders

(219)

Dividends to Diamondback

(255)

(5)

(250)

Dividends to other non-controlling interest

(7)

Change in ownership of consolidated subsidiaries, net

(20)

(79)

Net income (loss)

604

359

245

Ending balance (in shares) at Dec. 31, 2024

102,977,142

85,431,453

102,977,000

^[2]

85,431,000

^[2]

Ending balance at Dec. 31, 2024

3,907

1,569

118

2,220

Increase (Decrease) in Partners' Capital [Roll Forward]

Common shares/units issued to related party

3,599

Equity-based compensation

Vesting of restricted stock units (in shares)

^[2]

28,336,000

Change in ownership of consolidated subsidiaries, net

(117)

448

(565)

Repurchases of shares of Class A Common Stock under repurchase program (in shares)

^[2]

(4,016,000)

Repurchases as part of share/unit buyback

(153)

Net income (loss)

(68)

Net income (loss)

(206)

(68)

(138)

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Common shares/units issued for acquisition (in shares)

^[2]

38,536,000

38,020,000

Common shares/units issued for acquisition

$ 1,435

1,445

1,435

1,445

Common shares issued to related party (in shares)

^[2]

69,627,000

Common shares/units issued to related party

$ 3,599

Equity-based compensation

Net proceeds from the issuance of Common Stock (in shares)

^[2]

28,336,000

Net proceeds from the issuance of Common Stock

1,232

Conversion of Class B Common Stock to Class A Common Stock (in shares)

^[2]

5,054,000

(5,054,000)

Conversion of Class B Common Stock to Class A Common Stock

188

(188)

Issuance of shares upon vesting of equity awards (in shares)

^[2]

56,000

Dividends to stockholders

(327)

Dividends to Diamondback

(361)

Dividends to other non-controlling interest

(56)

Dividend equivalent rights payments

(1)

Change in ownership of consolidated subsidiaries, net

(117)

448

(565)

Repurchases of shares of Class A Common Stock under repurchase program (in shares)

^[2]

(4,016,000)

Repurchases of shares of Class A Common Stock under repurchase program

(153)

Repurchases of OpCo Units and cancellation of Class B Common Stock under repurchase program (in shares)

^[2]

(1,000,000)

Repurchases of OpCo Units and cancellation of Class B Common Stock under repurchase program

(41)

Net income (loss)

(206)

(68)

(138)

Ending balance (in shares) at Dec. 31, 2025

170,942,687

187,023,698

170,943,000

^[2]

187,024,000

^[2]

Ending balance at Dec. 31, 2025

$ 10,363

$ 4,726

$ (278)

$ 5,915

[1]	The par values of the outstanding shares of Class A Common Stock and Class B Common Stock each round to zero at December 31, 2023.
[2]	The par values of the outstanding shares of Class A Common Stock and Class B Common Stock each round to zero during the periods presented.

STOCKHOLDERS’ EQUITY (Tables)

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Schedule of Beneficial Ownership of Common Stock and OpCo Units

The following table presents the beneficial ownership of Common Stock and OpCo Units as of December 31, 2025:


	As of December 31, 2025
	Shares of Common Stock Beneficially Owned	Percentage Ownership(1)		OpCo Units Beneficially Owned	Percentage Ownership
Public equity holders of Class A Common Stock	170,942,687	46.5	%	—	—	%
Viper and subsidiaries	—	—	%	170,942,687	46.5	%
Diamondback and subsidiaries	155,058,093	42.1	%	155,058,093	42.1	%
Sitio OpCo former equity holders	29,565,308	8.0	%	29,565,308	8.0	%
TWR IV(1)	10,093,670	2.7	%	10,093,670	2.7	%
Morita Ranches Equity Recipients	2,400,297	0.7	%	2,400,297	0.7	%
Total Ownership(1)	368,060,055	100.0	%	368,060,055	100.0	%

(1)On a fully diluted basis, assuming TWR IV exercises the TWR Class B Option.

Schedule of Dividends Declared

The following table presents information regarding cash distributions and dividends paid during the years ended December 31, 2025, 2024 and 2023 (in millions except per share amounts):


	Distributions
Period	Amount per OpCo Unit		Operating Company Distributions to Non-Controlling Interests		Amount per Class A Common Share		Class A Common Stockholders(1)(2)		Declaration Date	Class A Common Stockholder Record Date	Payment Date
2025
Q4 2024	$	0.69	$	68	$	0.65	$	85	January 30, 2025	March 6, 2025	March 13, 2025
Q1 2025	$	0.70	$	117	$	0.57	$	75	May 1, 2025	May 15, 2025	May 22, 2025
Q2 2025	$	0.59	$	98	$	0.53	$	68	July 31, 2025	August 14, 2025	August 21, 2025
Q3 2025	$	0.66	$	134	$	0.58	$	99	October 30, 2025	November 13, 2025	November 20, 2025
2024
Q4 2023	$	0.69	$	63	$	0.56	$	48	February 15, 2024	March 5, 2024	March 12, 2024
Q1 2024	$	0.70	$	60	$	0.59	$	54	April 25, 2024	May 15, 2024	May 22, 2024
Q2 2024	$	0.76	$	65	$	0.64	$	59	August 1, 2024	August 15, 2024	August 22, 2024
Q3 2024	$	0.73	$	69	$	0.61	$	63	October 31, 2024	November 14, 2024	November 21, 2024
2023
Q4 2022	$	0.54	$	49	$	0.49	$	36	February 15, 2023	March 3, 2023	March 10, 2023
Q1 2023	$	0.42	$	38	$	0.33	$	24	April 26, 2023	May 11, 2023	May 18, 2023
Q2 2023	$	0.44	$	40	$	0.36	$	25	July 25, 2023	August 10, 2023	August 17, 2023
Q3 2023	$	0.70	$	64	$	0.57	$	49	November 2, 2023	November 16, 2023	November 24, 2023

(1)Dividends paid in the first quarter of 2024 include amounts paid to Diamondback for the 7,946,507 shares of Class A Common Stock then beneficially owned by Diamondback and distributions equivalent rights payments. As of March 31, 2024, Diamondback did not beneficially own any shares of Class A Common Stock.

(2)For distributions paid in 2023, includes amounts paid to Diamondback for the 731,500 common units then beneficially owned by Diamondback.

Schedule of Change in Ownership Interest

The following table summarizes the changes in stockholders’ equity due to changes in ownership interest during the period:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Net income (loss) attributable to the Company	$	(68)	$	359	$	200
Change in ownership of consolidated subsidiaries	448		59		(102)
Change from net income (loss) attributable to the Company’s stockholders and transfers with non-controlling interest	$	380	$	418	$	98

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

Schedule of Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities

Oil and natural gas interests include the following for the periods presented:


	December 31,
	2025		2024
	(In millions)
Oil and natural gas interests:
Proved properties	$	9,746	$	3,533
Unproved properties	4,910		2,180
Gross oil and natural gas interests	14,656		5,713
Accumulated depletion	(1,567)		(961)
Accumulated impairment	(888)		(120)
Oil and natural gas interests, net	12,201		4,632
Other property, equipment and land	8		6
Property, net of accumulated depletion and impairment	$	12,209	$	4,638

Balance of costs not subject to depletion:
Incurred in 2025	$	3,614
Incurred in 2024	562
Incurred in 2023	553
Prior	181
Total not subject to depletion	$	4,910

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


	December 31,
	2025		2024
	(In millions)
Oil and natural gas interests:
Proved	$	9,746	$	3,533
Unproved	4,910		2,180
Total oil and natural gas interests	14,656		5,713
Accumulated depletion	(1,567)		(961)
Accumulated impairment	(888)		(120)
Net oil and natural gas interests capitalized	$	12,201	$	4,632

Schedule of Cost Incurred in Oil and Gas Property Acquisition Activities

Costs incurred in oil and natural gas property acquisition activities are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Acquisition costs:
Proved properties	$	4,976	$	341	$	403
Unproved properties	3,968		830		758
Total	$	8,944	$	1,171	$	1,161

Schedule of Changes in Estimated Proved Reserves

The following table presents changes in estimated proved reserves, which were prepared in accordance with the rules and regulations of the SEC:


	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBOE)(1)
Proved Developed and Undeveloped Reserves:
As of December 31, 2022	79,004	209,964	34,902	148,900
Purchase of reserves in place	10,469	27,011	4,006	18,977
Extensions and discoveries	13,636	34,632	6,150	25,558
Revisions of previous estimates	(5,178)	11,101	3,466	138

Production	(8,028)	(19,130)	(3,108)	(14,324)
As of December 31, 2023	89,903	263,578	45,416	179,249
Purchase of reserves in place	7,891	20,310	3,665	14,941
Extensions and discoveries	13,099	33,498	6,254	24,936
Revisions of previous estimates	(6,472)	4,449	2,837	(2,894)
Divestitures	(919)	(4,605)	(451)	(2,138)
Production	(9,939)	(24,606)	(4,181)	(18,221)
As of December 31, 2024	93,563	292,624	53,540	195,873
Purchase of reserves in place	90,168	336,127	55,102	201,291
Extensions and discoveries	31,305	90,973	15,702	62,170
Revisions of previous estimates	(3,951)	(31,751)	(9,328)	(18,570)
Divestitures	(4)	(12)	(2)	(8)
Production	(17,875)	(51,676)	(8,233)	(34,721)
As of December 31, 2025	193,206	636,285	106,781	406,035

Proved Developed Reserves:
December 31, 2023	69,043	221,462	37,417	143,371
December 31, 2024	76,020	253,271	45,633	163,865
December 31, 2025	147,036	512,302	84,282	316,702

Proved Undeveloped Reserves:
December 31, 2023	20,860	42,116	7,999	35,878
December 31, 2024	17,543	39,353	7,907	32,009
December 31, 2025	46,170	123,983	22,499	89,333

The following table includes the changes in PUD reserves for 2025:


			MBOE
Beginning proved undeveloped reserves at December 31, 2024			32,009
Undeveloped reserves transferred to developed			(11,848)
Revisions			(5,643)
Purchases			28,395

Extensions and discoveries			46,420
Ending proved undeveloped reserves at December 31, 2025			89,333

Schedule of Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2025, 2024 and 2023:


	December 31,
	2025		2024		2023
	(In millions)
Future cash inflows	$	15,377	$	8,323	$	8,494
Future production taxes	(1,080)		(578)		(594)
Future income tax expense	(1,389)		(749)		(935)
Future net cash flows	12,908		6,996		6,965
10% discount to reflect timing of cash flows	(6,261)		(3,676)		(3,778)
Standardized measure of discounted future net cash flows(1)	$	6,647	$	3,320	$	3,187

(1)Includes a 54%, 48% and 51% non-controlling interest in the Operating Company at December 31, 2025, 2024 and 2023, respectively.

Schedule of Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids

The following table presents the SEC Prices as adjusted for differentials and contractual arrangements utilized in the computation of future cash inflows:


	December 31,
	2025		2024		2023


Oil (per Bbl)	$	64.80	$	75.61	$	77.93
Natural gas (per Mcf)	$	1.31	$	0.49	$	1.54
Natural gas liquids (per Bbl)	$	18.95	$	20.62	$	23.79

Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	3,320	$	3,187	$	3,454
Purchase of minerals in place	3,738		355		474
Divestiture of reserves	—		(51)		—
Sales of oil and natural gas, net of production costs	(1,252)		(793)		(667)
Extensions and discoveries	1,401		640		627
Net changes in prices and production costs	(279)		(438)		(1,405)
Revisions of previous quantity estimates	(374)		(85)		3
Net changes in income taxes	(370)		70		212
Accretion of discount	368		374		428
Net changes in timing of production and other	95		61		61
Standardized measure of discounted future net cash flows at the end of the period	$	6,647	$	3,320	$	3,187

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2025	Dec. 31, 2024
Common Class A
Common stock par value (usd per share)	$ 0.000001	$ 0.000001
Common stock authorized (in shares)	1,000,000,000	1,000,000,000
Common stock issued (in shares)	170,942,687	102,977,142
Common stock outstanding (in shares)	170,942,687	102,977,142
Common Class B
Common stock par value (usd per share)	$ 0.000001	$ 0.000001
Common stock authorized (in shares)	1,000,000,000	1,000,000,000
Common stock issued (in shares)	187,023,698	85,431,453
Common stock outstanding (in shares)	187,023,698	85,431,453

DEBT (Tables)

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Schedule of Maturities of Long-Term Debt

Long-term debt consisted of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
5.375% Senior Notes due 2027	$	—	$	430
4.900% Senior Notes due 2030	500		—
7.375% Senior Notes due 2031	—		400
5.700% Senior Notes due 2035	1,100		—
Term Loan	500		—
Revolving credit facility	105		261
Unamortized debt issuance costs	(15)		(6)
Unamortized discount costs	(4)		(2)
Total long-term debt	$	2,186	$	1,083

Schedule of Interest Income and Interest Expense Disclosure

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2025, 2024 and 2023:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Interest expense	$	103	$	74	$	48
Other fees and expenses	3		2		1
Less: interest income	10		2		2


Interest expense, net	$	96	$	74	$	47

DERIVATIVES

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

Commodity Contracts

The Company historically has used fixed price swap contracts, fixed price basis swap contracts, deferred premium puts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At December 31, 2025, the Company has puts, costless collars and fixed price basis swap contracts outstanding.

The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with put contracts for oil based on WTI Cushing and fixed price basis swaps for oil based on the spread between the WTI Cushing crude oil price and the Argus WTI Midland crude oil price. The Company’s fixed price basis swaps for natural gas are for the spread between the Waha Hub natural gas price and the Henry Hub natural gas price. The weighted average differential represents the amount of reduction to the WTI Cushing oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts. Under the Company’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Company, and when the settlement price is above the ceiling price, the Company is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company has entered into commodity derivative instruments only with counterparties that are also lenders under the 2025 Revolving Credit Facility and our counterparties have been deemed an acceptable credit risk. As such, collateral is not required from either the counterparties or the Company on its outstanding commodity derivative contracts. Market risks involved in the Company’s use of derivative instruments relate to its potential inability to realize the benefits of any increases in commodity prices above the prices established by its derivative contracts.

As of December 31, 2025, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.


					Swaps	Collars		Puts
Settlement Month	Settlement Year	Type of Contract	Bbls/MMBtu Per Day	Index	Weighted Average Differential	Weighted Average Floor Price	Weighted Average Ceiling Price	Strike Price	Deferred Premium
OIL
Jan. - Mar.	2026	Puts	40,000	WTI Cushing	$—	$—	$—	$51.75	$(1.56)
Apr. - Jun.	2026	Puts	20,000	WTI Cushing	$—	$—	$—	$48.13	$(1.35)
NATURAL GAS
Jan. - Dec.	2026	Basis Swaps	80,000	Waha Hub	$(1.61)	$—	$—	$—	$—
Jan. - Dec.	2027	Basis Swaps	40,000	Waha Hub	$(1.40)	$—	$—	$—	$—
Jan. - Dec.	2026	Costless Collar	60,000	Henry Hub	$—	$2.75	$6.64	$—	$—

Treasury Locks

During the third quarter of 2025, the Company entered into certain treasury lock contracts to reduce the forecasted interest rate risk associated with the issuance of the Guaranteed Senior Notes. The treasury locks were terminated and settled upon issuance of the Guaranteed Senior Notes with a gain of $3 million recognized under the caption “Gain (loss) on derivative instruments, net” on the consolidated statements of operations for the year ended December 31, 2025.

Contingent Liability

The change in fair value of the 2026 WTI Contingent Liability is recognized in “Gain (loss) on derivative instruments, net” on the Company’s consolidated statements of operations for the years ended December 31, 2025 and 2024.

Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 11—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts	$	31	$	15	$	(26)
2026 WTI Contingent Liability	10		(4)		—
Treasury locks	3		—		—
Total	$	44	$	11	$	(26)

Net cash receipts (payments) on derivatives:
Commodity contracts	$	27	$	(3)	$	(13)

Treasury locks	3		—		—
Total	$	30	$	(3)	$	(13)

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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+ Details

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Changes in Estimated Proved Reserves (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2025 MBoe MBbls MMcf	Dec. 31, 2024 MBoe MBbls MMcf	Dec. 31, 2023 MBoe MBbls MMcf	Dec. 31, 2022 MBoe
Proved Developed and Undeveloped Reserves [Roll Forward]
Total, beginning balance (in MBOE) \| MBoe	195,873	179,249	148,900
Purchase of reserves in place (in MBOE) \| MBoe	201,291	14,941	18,977
Extensions and discoveries (in MBOE) \| MBoe	62,170	24,936	25,558
Revision of previous estimates (in MBOE) \| MBoe	(18,570)	(2,894)	138
Divestitures (in MBOE) \| MBoe	(8)	(2,138)
Production (in MBOE) \| MBoe	(34,721)	(18,221)	(14,324)
Total, ending balance (in MBOE) \| MBoe	406,035	195,873	179,249
Proved developed reserves (in MBOE) \| MBoe	316,702	163,865	143,371
Proved undeveloped reserves (in MBOE) \| MBoe	89,333	32,009	35,878
Total proved reserves attributable to a non-controlling interest \| MBoe	219,259	94,019	91,417	81,895
Crude Oil, Condensate, and Natural Gas Liquids (NGL)
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	93,563	89,903	79,004
Purchase of reserves in place	90,168	7,891	10,469
Extensions and discoveries	31,305	13,099	13,636
Revisions of previous estimates	(3,951)	(6,472)	(5,178)
Divestitures	(4)	(919)
Production	(17,875)	(9,939)	(8,028)
End of period	193,206	93,563	89,903
Proved developed reserves (volume)	147,036	76,020	69,043
Proved undeveloped reserve (volume)	46,170	17,543	20,860
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period \| MMcf	292,624	263,578	209,964
Purchase of reserves in place \| MMcf	336,127	20,310	27,011
Extensions and discoveries \| MMcf	90,973	33,498	34,632
Revisions of previous estimates \| MMcf	(31,751)	4,449	11,101
Divestitures \| MMcf	(12)	(4,605)
Production \| MMcf	(51,676)	(24,606)	(19,130)
End of period \| MMcf	636,285	292,624	263,578
Proved developed reserves (volume) \| MMcf	512,302	253,271	221,462
Proved undeveloped reserve (volume) \| MMcf	123,983	39,353	42,116
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	53,540	45,416	34,902
Purchase of reserves in place	55,102	3,665	4,006
Extensions and discoveries	15,702	6,254	6,150
Revisions of previous estimates	(9,328)	2,837	3,466
Divestitures	(2)	(451)
Production	(8,233)	(4,181)	(3,108)
End of period	106,781	53,540	45,416
Proved developed reserves (volume)	84,282	45,633	37,417
Proved undeveloped reserve (volume)	22,499	7,907	7,999

DEBT - Additional Information (Details) $ in Millions			3 Months Ended	12 Months Ended
DEBT - Additional Information (Details) $ in Millions	Jul. 23, 2025 USD ($)	Jun. 12, 2025 USD ($) extensionOption	Jun. 30, 2025 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Line of Credit Facility [Line Items]
Loss on extinguishment of debt				$ 32	$ 0	$ 0
Guaranteed Senior Notes \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, face amount	$ 1,600
Proceeds from debt issuance	1,580
Proceeds from debt issuance used for debt redemption	824
4.900% Senior Notes due 2030 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, face amount	$ 500
Debt instrument, interest rate, stated percentage	4.90%			4.90%
5.700% Senior Notes due 2035 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, face amount	$ 1,100
Debt instrument, interest rate, stated percentage	5.70%			5.70%
5.375% Senior Notes Due 2027 And 7.375% Senior Notes Due 2031 \| Senior Notes
Line of Credit Facility [Line Items]
Repayments of senior notes	$ 780
7.875% Senior Notes Due 2028 \| Senior Notes \| Sitio Royalties Corp.
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	7.875%
5.375% Senior Notes due 2027 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage			5.375%	5.375%
Repayments of senior notes			$ 50
Repurchase amount of debt			$ 50
Debt repurchased, average percentage of par value			99.70%
Deposits	$ 390
Debt instrument, redemption price, percentage	100.00%
7.375% Senior Notes due 2031 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	7.375%			7.375%
Repayments of senior notes	$ 434
Redemption premium, percentage	106.767%
Loss on extinguishment of debt	$ 32
Revolving credit facility \| Revolving Credit Facility, 2025 \| Line of Credit \| Viper Energy Partners LLC
Line of Credit Facility [Line Items]
Maximum borrowing capacity		$ 1,500
Number of options to extend maturity date \| extensionOption		3
Extension period		1 year
Amount outstanding under credit facility				$ 105
Remaining borrowing capacity				$ 1,400
Debt covenant, total net debt to capitalization ratio		65.00%
Revolving credit facility \| Revolving Credit Facility, 2025 \| Line of Credit \| Viper Energy Partners LLC \| Minimum
Line of Credit Facility [Line Items]
Commitment fee on the unused portion of the borrowing base		0.125%
Revolving credit facility \| Revolving Credit Facility, 2025 \| Line of Credit \| Viper Energy Partners LLC \| Maximum
Line of Credit Facility [Line Items]
Commitment fee on the unused portion of the borrowing base		0.325%
Revolving credit facility \| Revolving Credit Facility, 2025 \| Line of Credit \| Viper Energy Partners LLC \| Fed Funds Effective Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.50%
Revolving credit facility \| Revolving Credit Facility, 2025 \| Line of Credit \| Viper Energy Partners LLC \| SOFR
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.00%
Basis spread on variable rate, floor		1.00%
Revolving credit facility \| Revolving Credit Facility 2025 And 2018 \| Line of Credit \| Viper Energy Partners LLC
Line of Credit Facility [Line Items]
Weighted average interest rate				6.02%
Revolving credit facility \| Revolving Credit Facility, 2018 \| Line of Credit \| Viper Energy Partners LLC
Line of Credit Facility [Line Items]
Weighted average interest rate					7.34%	7.41%
Revolving credit facility \| Revolving Credit Facility, Alternate Base Rate Loans, 2025 \| Line of Credit \| Viper Energy Partners LLC \| Base Rate \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.125%
Revolving credit facility \| Revolving Credit Facility, Alternate Base Rate Loans, 2025 \| Line of Credit \| Viper Energy Partners LLC \| Base Rate \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.00%
Revolving credit facility \| Revolving Credit Facility, Term SOFR Loans, 2025 \| Line of Credit \| Viper Energy Partners LLC \| SOFR \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.125%
Revolving credit facility \| Revolving Credit Facility, Term SOFR Loans, 2025 \| Line of Credit \| Viper Energy Partners LLC \| SOFR \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate		2.00%
Swingline Loan \| Revolving Credit Facility, 2025 \| Line of Credit \| Viper Energy Partners LLC
Line of Credit Facility [Line Items]
Maximum borrowing capacity		$ 50
Letter of Credit \| Revolving Credit Facility, 2025 \| Line of Credit \| Viper Energy Partners LLC
Line of Credit Facility [Line Items]
Maximum borrowing capacity		$ 5
Unsecured Debt \| Term Loan \| Line of Credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 500
Weighted average interest rate				5.72%
Basis spread on variable rate	0.50%
Commitment fee on the unused portion of the borrowing base	0.20%
Unsecured Debt \| Term Loan \| Line of Credit \| SOFR
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Basis spread on variable rate, floor	1.00%
Unsecured Debt \| Term Loan Credit Agreement, Alternate Base Rate Loans \| Line of Credit \| Base Rate \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.25%
Unsecured Debt \| Term Loan Credit Agreement, Alternate Base Rate Loans \| Line of Credit \| Base Rate \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.125%
Unsecured Debt \| Term Loan Credit Agreement, Term SOFR Loans \| Line of Credit \| SOFR \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.25%
Unsecured Debt \| Term Loan Credit Agreement, Term SOFR Loans \| Line of Credit \| SOFR \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.125%

DEBT - Schedule of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2025	Jul. 23, 2025	Jun. 30, 2025	Dec. 31, 2024
Line of Credit Facility [Line Items]
Unamortized debt issuance costs	$ (15)			$ (6)
Unamortized discount costs	(4)			(2)
Total long-term debt	2,186			1,083
Revolving credit facility \| Line of Credit
Line of Credit Facility [Line Items]
Long term debt, gross	$ 105			261
5.375% Senior Notes due 2027 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	5.375%		5.375%
Long term debt, gross	$ 0			430
4.900% Senior Notes due 2030 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	4.90%	4.90%
Long term debt, gross	$ 500			0
7.375% Senior Notes due 2031 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	7.375%	7.375%
Long term debt, gross	$ 0			400
5.700% Senior Notes due 2035 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	5.70%	5.70%
Long term debt, gross	$ 1,100			0
Term Loan \| Unsecured Debt \| Line of Credit
Line of Credit Facility [Line Items]
Long term debt, gross	$ 500			$ 0

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating income:
Royalty income	$ 1,346	$ 854	$ 717
Other operating income	1	1	1
Total operating income	1,395	861	828
Costs and expenses:
Production and ad valorem taxes	94	61	50
Depletion	607	214	146
Impairment	768	0	0
Other operating expenses	31	0	1
Total costs and expenses	1,535	294	208
Income (loss) from operations	(140)	567	620
Other income (expense):
Interest expense, net	(96)	(74)	(47)
Gain (loss) on derivative instruments, net	44	11	(26)
Gain (loss) on early extinguishment of debt	(32)	0	0
Other income (expense), net	(1)	0	0
Total other income (expense), net	(85)	(63)	(73)
Income (loss) before income taxes	(225)	504	547
Provision for (benefit from) income taxes	(19)	(100)	46
Net income (loss)	(206)	604	501
Net income (loss) attributable to non-controlling interest	(138)	245	301
Net income (loss) attributable to Viper Energy, Inc.	$ (68)	$ 359	$ 200
Net income (loss) attributable to common shares:
Basic (dollars per shares)	$ (0.48)	$ 3.82	$ 2.69
Diluted (dollars per shares)	$ (0.48)	$ 3.82	$ 2.69
Weighted average number of common shares outstanding:
Basic (in shares)	142,530	93,932	74,176
Diluted (in shares)	142,530	93,932	74,176
Oil income
Operating income:
Royalty income	$ 1,131	$ 750	$ 619
Natural gas income
Operating income:
Royalty income	56	15	31
Natural gas liquids income
Operating income:
Royalty income	159	89	67
Nonrelated Party
Operating income:
Lease bonus income	24	6	2
Costs and expenses:
General and administrative expenses	18	8	7
Related Party
Operating income:
Lease bonus income	24	0	108
Costs and expenses:
General and administrative expenses	$ 17	$ 11	$ 4

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2025

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis on the Company’s consolidated balance sheets, including the Company’s commodity derivative instruments and the 2026 WTI Contingent Liability.

The fair values of the Company’s commodity derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third-party, the contracted notional volumes and time to maturity. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The fair value of the 2026 WTI Contingent Liability was estimated using observable market data and a Monte Carlo pricing model, which are considered Level 2 inputs in the fair value hierarchy.


	As of December 31, 2025
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	37	$	—	$	37	$	(9)	$	28


Liabilities:
Other current liabilities	$	—	$	9	$	—	$	9	$	(9)	$	—
Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	20	$	—	$	20	$	—	$	20
Other long-term liabilities	$	—	$	7	$	—	$	7	$	—	$	7


	As of December 31, 2024
Balance Sheet Classification	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Prepaid expenses and other current assets	$	—	$	24	$	—	$	24	$	(6)	$	18



Liabilities:
Other current liabilities	$	—	$	8	$	—	$	8	$	(6)	$	2

Accrued liabilities (2026 WTI Contingent Liability)	$	—	$	30	$	—	$	30	$	—	$	30

Assets and Liabilities Not Recorded at Fair Value

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:


	December 31, 2025				December 31, 2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
Debt	$	2,186	$	2,233	$	1,083	$	1,105

The fair values of our current or previous revolving credit facility, as applicable, and the Term Loan approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair values of the Notes and Guaranteed Senior Notes were determined using the quoted market price at each period end, a Level 1 classification in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include mineral and royalty interests acquired in asset acquisitions and subsequent write-downs of the Company’s proved oil and natural gas interests to fair value when they are impaired or held for sale.

See Note 2—Summary of Significant Accounting Policies and Note 5—Oil and Natural Gas Interests for further discussion of non-recurring fair value adjustments.

Fair Value of Financial Assets

The Company has other financial instruments consisting of cash and cash equivalents, royalty income receivable, income tax receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and income taxes payable. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

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+ Details

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Schedule of Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consist of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
Derivative instruments	$	28	$	18
Prepaid expenses	13		11
Other	9		2
Total prepaid expenses and other current assets	$	50	$	31

Schedule of Accrued Liabilities

Accrued liabilities consist of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
Interest payable	$	39	$	10
Ad valorem taxes payable	34		20

Acquisition adjustment accrual	4		9
2026 WTI Contingent Liability	20		—
Other	10		4
Total accrued liabilities	$	107	$	43

OIL AND NATURAL GAS INTERESTS

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following for the periods presented:


	December 31,
	2025		2024
	(In millions)
Oil and natural gas interests:
Proved properties	$	9,746	$	3,533
Unproved properties	4,910		2,180
Gross oil and natural gas interests	14,656		5,713
Accumulated depletion	(1,567)		(961)
Accumulated impairment	(888)		(120)
Oil and natural gas interests, net	12,201		4,632
Other property, equipment and land	8		6
Property, net of accumulated depletion and impairment	$	12,209	$	4,638

Balance of costs not subject to depletion:
Incurred in 2025	$	3,614
Incurred in 2024	562
Incurred in 2023	553
Prior	181
Total not subject to depletion	$	4,910

As of December 31, 2025, and 2024, the Company had mineral and royalty interests representing approximately 96,003 and 35,671 net royalty acres, respectively.

Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves can be made. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within nine to 12 years. All costs incurred not subject to depletion are classified as acquisition costs.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. As a result of its ceiling test, the Company recorded aggregate non-cash ceiling test impairments for the year ended December 31, 2025 of $768 million. No impairment expense was recorded on the Company’s oil and natural gas interests for the years ended December 31, 2024 and 2023, based on the results of the respective quarterly ceiling tests. In addition to commodity prices, the Company’s production rates, levels of proved reserves, transfers of unevaluated properties, income tax rate assumptions and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If future SEC Prices decline as compared to the commodity prices used in prior quarters, the Company could have further write-downs in subsequent quarters, which may be material.

SEGMENT INFORMATION	12 Months Ended
SEGMENT INFORMATION	Dec. 31, 2025
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION As of December 31, 2025, the Company is managed on a consolidated basis as a single operating and reportable segment which is focused on owning and acquiring mineral and royalty interests primarily in the Permian Basin in West Texas. The Company’s operating segment primarily derives its revenue from customers through the receipt of royalty income on the sale of oil and natural gas products as well as other immaterial service contracts. See Note 3—Revenue from Contracts with Customers for further discussion of the Company’s sources of revenue. The Company’s Chief Operating Decision Maker (“CODM”) is a senior executive committee that is comprised of the Company’s Chief Executive Officer and President. The CODM uses the Company’s consolidated financial results to assess performance, allocate resources and make key operating decisions, obtaining the board’s approval as required. The measures of segment profit or loss and total assets utilized by the CODM are net income and total assets, as reported on the consolidated statements of operations and the consolidated balance sheets, respectively. The significant expense categories, their amounts and other segment items that are regularly provided to the CODM are those that are reported in the Company’s consolidated statements of operations as well as interest income and interest expense in Note 6—Debt. The CODM uses consolidated net income as a measure of profitability to evaluate segment performance and to make capital allocation decisions such as reinvestment in the business or return of capital through the payment of base and variable dividends or repurchases under the share repurchase program.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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+ Details

INCOME TAXES - Schedule of Reconciliation of Statutory Federal Income tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Amount
Income tax expense (benefit) at the federal statutory rate (21%)	$ (47)	$ 106	$ 115
Tax Jurisdiction of Domicile [Extensible Enumeration]	UNITED STATES
State income tax, net of federal income tax effect	$ (1)	2	2
Changes in valuation allowances	0	(156)	(8)
Impact of nontaxable noncontrolling interest	29	(52)	(63)
Total provision (benefit) from income taxes	$ (19)	$ (100)	$ 46
Percentage of Income (Loss) Before Income Taxes
Income tax expense (benefit) at the federal statutory rate (21%)	21.00%	21.00%	21.00%
State income tax, net of federal income tax effect	0.00%	0.00%	0.00%
Changes in valuation allowances	0.00%	(31.00%)	(1.00%)
Impact of nontaxable noncontrolling interest	(13.00%)	(10.00%)	(12.00%)
Provision for (benefit from) income taxes	8.00%	(20.00%)	8.00%

EARNINGS PER COMMON SHARE

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

EARNINGS PER COMMON SHARE

The net income (loss) per common share on the consolidated statements of operations is based on the net income (loss) attributable to the Company’s Class A Common Stock for the years ended December 31, 2025, 2024 and 2023.

Basic and diluted earnings per common share are calculated using the two-class method. The two-class method is an earnings allocation proportional to the respective ownership among holders of Class A Common Stock and participating securities. Basic net income (loss) per common share is calculated by dividing net income (loss) by the weighted-average shares of Class A Common Stock outstanding during the period. Diluted net income (loss) per common share gives effect, when applicable, to unvested restricted stock units and performance restricted stock units granted under the LTIP.

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:


	Year Ended December 31,
	2025		2024		2023
	(In millions, except per share amounts, shares in thousands)
Net income (loss) attributable to the period	$	(68)	$	359	$	200
Less: net income (loss) allocated to participating securities(1)	1		—		—
Net income (loss) attributable to common stockholders	$	(69)	$	359	$	200
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	142,530		93,932		74,176
Effect of dilutive securities:
Potential common shares issuable(2)	—		—		—
Diluted weighted average common shares outstanding	142,530		93,932		74,176
Net income (loss) per common share, basic	$	(0.48)	$	3.82	$	2.69
Net income (loss) per common share, diluted	$	(0.48)	$	3.82	$	2.69

(1)Unvested restricted stock units and performance restricted stock units that contain non-forfeitable dividend equivalent rights are considered participating securities and are therefore included in the earnings per share calculation pursuant to the two-class method.

(2)For the year ended December 31, 2025, 110,342 potential common shares were excluded from the computation of diluted earnings per common share because their inclusion would have been anti-dilutive as a result of recording a net loss attributable to the common shareholders for the period. For the years ended December 31, 2024 and 2023 no significant potential common shares were excluded from the computation of diluted earnings per common share.

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Future cash inflows	$ 15,377	$ 8,323	$ 8,494
Future production taxes	(1,080)	(578)	(594)
Future income tax expense	(1,389)	(749)	(935)
Future net cash flows	12,908	6,996	6,965
10% discount to reflect timing of cash flows	(6,261)	(3,676)	(3,778)
Standardized measure of discounted future net cash flows	$ 6,647	$ 3,320	$ 3,187	$ 3,454
VNOM Holding Company LLC
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Percentage by noncontrolling owners	54.00%
Viper Energy Partners LLC
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Percentage by noncontrolling owners		48.00%	51.00%

STOCKHOLDERS’ EQUITY - Schedule of Ownership Interest in Subsidiary Changes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to the Company	$ (68)	$ 359	$ 200
Change in ownership of consolidated subsidiaries	(117)	(20)	0
Affiliated Entity
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to the Company	(68)	359	200
Change in ownership of consolidated subsidiaries	448	59	(102)
Change from net income (loss) attributable to the Company’s stockholders and transfers with non-controlling interest	$ 380	$ 418	$ 98

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

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+ Details

INCOME TAXES

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

INCOME TAXES

The Company’s total income tax benefit for the year ended December 31, 2025, differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period primarily due to net loss attributable to the non-controlling interest. For the year ended December 31, 2024, the Company’s total income tax benefit differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the release of the remaining valuation allowance during the fourth quarter and net income attributable to non-controlling interests. For the year ended December 31, 2023, total income tax expense differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of reductions to the valuation allowance.

The components of the provision for income taxes for the years ended December 31, 2025, 2024 and 2023 are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Current income tax provision (benefit):
Federal	$	60	$	47	$	50
State	4		2		3
Total current income tax provision (benefit)	64		49		53
Deferred income tax provision (benefit):
Federal	(78)		(148)		(7)
State	(5)		(1)		—
Total deferred income tax provision (benefit)	(83)		(149)		(7)
Total provision (benefit) from income taxes	$	(19)	$	(100)	$	46

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:


	Year Ended December 31,
	2025				2024				2023
	Amount (In millions)		Percentage of Income (Loss) Before Income Taxes		Amount (In millions)		Percentage of Income (Loss) Before Income Taxes		Amount (In millions)		Percentage of Income (Loss) Before Income Taxes
Income tax expense (benefit) at the federal statutory rate (21%)	$	(47)	21	%	$	106	21	%	$	115	21	%


State income tax, net of federal income tax effect(1)	(1)		—	%	2		—	%	2		—	%


Changes in valuation allowances	—		—	%	(156)		(31)	%	(8)		(1)	%

Nontaxable or nondeductible items:
Impact of nontaxable noncontrolling interest	29		(13)	%	(52)		(10)	%	(63)		(12)	%
Provision for (benefit from) income taxes	$	(19)	8	%	$	(100)	(20)	%	$	46	8	%

(1)State taxes in Texas make up the majority (greater than 50%) of the tax effect in this category.

The components of the Company’s deferred tax assets and liabilities as of December 31, 2025 and 2024 are as follows:


	Year Ended December 31,
	2025		2024
	(In millions)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	5	$	—
Investment in the Operating Company	28		185


Total deferred tax assets	33		185
Valuation allowance	—		—
Net deferred tax assets	33		185




Net deferred tax assets (liabilities)	$	33	$	185

At December 31, 2025, the Company had net deferred tax assets of approximately $33 million, including $5 million in federal capital loss carryforwards expiring in 2027 and immaterial state operating loss carryforwards. Deferred taxes are provided on the difference between the Company’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in the Operating Company.

In connection with the closing of the Sitio Acquisition, the Company acquired prepaid income tax balances of approximately $14 million and deferred tax assets of $5 million related to loss carryforwards. The Company also recognized a deferred tax liability of approximately $122 million. The Company’s federal loss carryforwards acquired from Sitio are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), which subjects tax attributes to limitation upon an “ownership change” (as defined in the Code). In general, an ownership change occurs if there is a cumulative increase in the ownership of a corporation’s stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year look back period. Based on Sitio’s fair market value, the Company has determined that the applicable annual limitation exceeds the loss carryforwards acquired from Sitio. As such, the Company believes that the application of Section 382 of the Code will not have an adverse effect on future usage of its federal tax attributes.

During the fourth quarter of 2024, the Company released its remaining valuation allowance of $156 million as a result of management’s assessment of the realizability of future taxable income, which primarily contributed to the discrete income tax benefit of $149 million for the year ended December 31, 2024. During the year ended December 31, 2023, the Company recognized a discrete income tax benefit of $7 million related to a partial release of its beginning-of-the-year valuation allowance, based on a change in judgment about the realizability of its deferred tax assets in future years.

In March 2024, as part of the Diamondback Offering, the Company recognized a $28 million increase in its deferred tax asset and an $11 million increase in its valuation allowance through additional paid-in capital.

At December 31, 2025, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The Company’s 2022 through 2025 tax years remain open to examination by tax authorities.

On July 4, 2025, H.R. 1, commonly known as the One Big Beautiful Bill Act (the “OBBB”), was enacted. The OBBB included multiple provisions applicable to U.S. income taxes for businesses, including immediate expensing of research or experimental expenses, bonus depreciation for qualified tangible property, deductible intangible drilling costs for purposes of the corporate “book” minimum tax and enhancements to limits on business interest expense deductions. The Company accounted for the OBBB in the period of enactment and concluded there was not a material impact to the Company’s current or deferred income tax balances.

- Definition

The entire disclosure for income tax.

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-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
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+ Details

REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Total royalty income	$ 1,346	$ 854	$ 717
Revenue Generated from Diamondback Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	741	459	435
Revenue Generated from Third-Party Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	605	395	282
Oil income
Disaggregation of Revenue [Line Items]
Total royalty income	1,131	750	619
Oil income \| Revenue Generated from Diamondback Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	612	398	377
Oil income \| Revenue Generated from Third-Party Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	519	352	242
Natural gas income
Disaggregation of Revenue [Line Items]
Total royalty income	56	15	31
Natural gas income \| Revenue Generated from Diamondback Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	31	10	16
Natural gas income \| Revenue Generated from Third-Party Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	25	5	15
Natural gas liquids income
Disaggregation of Revenue [Line Items]
Total royalty income	159	89	67
Natural gas liquids income \| Revenue Generated from Diamondback Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	98	51	42
Natural gas liquids income \| Revenue Generated from Third-Party Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	$ 61	$ 38	$ 25

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

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- Definition

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

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+ Details

COMMITMENTS AND CONTINGENCIES	12 Months Ended
COMMITMENTS AND CONTINGENCIES	Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES The Company is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business. While the ultimate outcome of any pending proceedings, disputes or claims and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Insider Trading Policies and Procedures	12 Months Ended
Insider Trading Policies and Procedures	Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2025
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with GAAP. All material intercompany balances and transactions are eliminated in consolidation. The Company reports its operations in one reportable segment.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.
Use of Estimates	Use of Estimates Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities as of the date of the consolidated financial statements. Actual results could differ from those estimates. Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, geopolitical global conflicts, higher interest rates, effects of tariffs, actions taken by OPEC and its non-OPEC allies, known collectively as OPEC+, global supply chain disruptions, measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been and may continue to be impacted materially as a result of these events and changing market conditions. Such circumstances generally increase uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves, including those acquired by the Company, and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests, estimates of third-party operated royalty income related to expected sales volumes and prices, the recoverability of costs of unevaluated properties and estimates of income taxes, including deferred tax valuation allowances. Other areas requiring estimation include commodity derivatives and various fair values of non-oil and gas assets and liabilities.
Revenue from Contracts with Customers	Revenue from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index. The Company earns lease bonus income by leasing its mineral interests to exploration, development and production companies. The Company recognizes lease bonus income when a lease agreement has been executed and payment is determined to be collectible. Royalty Income from Oil, Natural Gas and Natural Gas Liquids Sales The Company’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the operator of the properties in which the Company owns a royalty interest sells the Company’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Company collects its percentage royalty based on the revenue generated. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction Price Allocated to Remaining Performance Obligations The Company’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of the Company’s royalty income contracts. Contract Balances Under the Company’s royalty income contracts, it generally has the right to receive its interest in the gross proceeds collected by the operator from third-party purchasers of the Company’s production once production has occurred, at which point payment is unconditional. Accordingly, the Company’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606. Prior-Period Performance Obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered. As a result, the Company is required to estimate the amount of royalty income to be received based upon the Company’s royalty interest. The Company records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the operator. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded. Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained from third-party purchasers by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition costs from third parties are capitalized and amortized on a composite unit of production method based on proved oil, natural gas and natural gas liquids reserves. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas and natural gas liquids. Acquisitions of mineral and royalty interests from related parties are typically recorded at the parent’s historical carrying value and related transaction costs are expensed as incurred in accordance with guidance in ASC 805 for transactions between entities under common control. At December 31, 2025, and 2024, the Company’s oil and natural gas properties consisted primarily of mineral interests in oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $17.48, $11.77 and $10.20 for the years ended December 31, 2025, 2024 and 2023, respectively. Depletion for oil and natural gas properties was $607 million, $214 million and $146 million for the years ended December 31, 2025, 2024 and 2023, respectively. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized oil and natural gas interests net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, (ii) the cost of properties not being amortized, if any, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. See Note 5—Oil and Natural Gas Interests for additional discussion of the Company’s oil and natural gas properties. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property at least annually for possible impairment. The Company 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: intent of the operator to drill; remaining lease term with the current operator; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Royalty Income Receivable	Royalty Income Receivable Royalty income receivables consist of receivables for sales of oil, natural gas and natural gas liquids made by the Company’s third-party operators and Diamondback to third-party purchasers. The operators remit payment for production directly to the Company. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work, which is required to be completed by the operator before payments are released. Royalty income receivables are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Company when collection is deemed doubtful. Royalty income receivables outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance utilizing the loss-rate method, which considers a number of factors, including the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific royalty income receivables when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. At December 31, 2025 and 2024, the Company’s allowance for expected losses was immaterial.
Concentrations	Concentrations The Company is subject to risk resulting from the concentration of its royalty income in producing oil and natural gas properties and receivables with several significant operators. For the year ended December 31, 2025, two operators each accounted for more than 10% of royalty income: Diamondback (55%) and ExxonMobil Corporation (14%). For the year ended December 31, 2024, two operators each accounted for more than 10% of royalty income: Diamondback (54%) and Pioneer Natural Resources (11%). For the year ended December 31, 2023, one operator accounted for more than 10% of royalty income: Diamondback (61%). Each of the Company’s operators sell to multiple purchasers. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact the Company’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Derivative Instruments	Derivative Instruments The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”
Income Taxes	Income Taxes The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities, and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively.
Non-Controlling Interest	Non-Controlling Interest Non-controlling interest in the accompanying consolidated financial statements represents the ownership interests of Diamondback, former equity holders of Sitio Royalties Operating Partnership, LP (“Sitio OpCo”), Tumbleweed Royalty IV, LLC (“TWR IV”) and the Morita Ranches Equity Recipients (as defined and discussed in Note 4—Acquisitions and Divestitures) in the net assets of the Operating Company. When the non-controlling interests’ relative ownership in the Operating Company changes, adjustments to non-controlling interest and stockholders’ equity, tax effected, will occur. Because these changes in the Company’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 Company’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.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The- Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.
Debt Issuance Costs	Debt Issuance Costs Other assets include capitalized costs related to our current credit facility, the previous credit facility and the Term Loan (as defined and discussed in Note 6—Debt) of $21 million and $18 million, and accumulated amortization of those costs over the term of the respective credit facilities of $13 million and $11 million as of December 31, 2025 and 2024, respectively. Long-term debt includes capitalized costs related to the Guaranteed Senior Notes. The costs associated with the Guaranteed Senior Notes are netted against the Guaranteed Senior Notes’ balances and amortized over the term of the Guaranteed Senior Notes using the effective interest method.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently Adopted Pronouncements In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated, and provides additional requirements regarding income taxes paid. The Company adopted the amendments in 2025 and applied the guidance on a retrospective basis. Adoption of the update resulted in additional disclosures in Note 9—Income Taxe s but did not impact the Company’s financial position, results of operations or liquidity. In September 2025, the FASB issued ASU 2025-07, “Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606) – Derivatives Scope Refinements and Scope Clarification for Share-Based Noncash Consideration from a Customer in a Revenue Contract.” The ASU addresses (i) the application of derivative accounting to contracts that include features based on the operations or activities of one of the parties to the contract and (ii) diversity in practice related to accounting for share-based noncash consideration from a customer. The Company elected to early-adopt this amendment in 2025 and applied the guidance on a prospective basis. Adoption of the update did not impact the Company’s historical financial position, results of operations or liquidity; however, the guidance may affect whether certain new arrangements qualify for derivative accounting. Accounting Pronouncements Not Yet Adopted In November 2024, the FASB issued ASU 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses,” which requires additional disclosure about specified categories of expenses included in relevant expense captions presented on the income statement. The amendments are effective for annual periods beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity. The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.
Fair Value Measurement	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis on the Company’s consolidated balance sheets, including the Company’s commodity derivative instruments and the 2026 WTI Contingent Liability. The fair values of the Company’s commodity derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third-party, the contracted notional volumes and time to maturity. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The fair value of the 2026 WTI Contingent Liability was estimated using observable market data and a Monte Carlo pricing model, which are considered Level 2 inputs in the fair value hierarchy.

STOCKHOLDERS’ EQUITY - Additional Information (Details) - USD ($)			1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 03, 2025	Sep. 13, 2024	Oct. 31, 2023	Dec. 31, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Class of Stock [Line Items]
Amount of shares repurchased					$ 41,000,000
Intended quarterly dividends					75.00%
Cash Distribution
Class of Stock [Line Items]
Distribution made to limited partner, distribution date, period after quarter end					60 days
Repurchase Program
Class of Stock [Line Items]
Authorized amount in repurchase program					$ 750,000,000
Amount of shares repurchased					$ 194,000,000
2023 Viper Issuance of Common Units to Diamondback
Class of Stock [Line Items]
Number of shares sold			7,215,007
Sale of stock (usd per share)			$ 27.72
Sale of stock, consideration received on transaction			$ 200,000,000
Common Class A
Class of Stock [Line Items]
Common stock issued (in shares)					170,942,687	102,977,142
Common stock outstanding (in shares)					170,942,687	102,977,142
Amount of shares repurchased				$ 29,000,000
Repurchased shares (in shares)				1,000,000
Common Class A \| Repurchase Program
Class of Stock [Line Items]
Amount of shares repurchased						$ 0	$ 95,000,000
Remaining authorized repurchase amount					$ 241,000,000
Common Class A \| 2025 Equity Offering
Class of Stock [Line Items]
Number of shares sold	28,336,000
Sale of stock (usd per share)	$ 44.50
Sale of stock, consideration received on transaction	$ 1,200,000,000
Common Class A \| Over-Allotment Option
Class of Stock [Line Items]
Number of shares sold	3,696,000	1,500,000
Common Class A \| 2024 Equity Offering
Class of Stock [Line Items]
Number of shares sold		11,500,000
Sale of stock (usd per share)		$ 42.50
Sale of stock, consideration received on transaction		$ 476,000,000
Common Class B
Class of Stock [Line Items]
Common stock issued (in shares)					187,023,698	85,431,453
Common stock outstanding (in shares)					187,023,698	85,431,453
Common stock, conversion basis (in shares)					1
Required dividend payment					$ 20,000
Common Class B \| TWR Class B Option \| TWR IV
Class of Stock [Line Items]
Class of warrant or right, securities called by warrants or rights (in shares)					10,093,670
Operating Company Units
Class of Stock [Line Items]
Common stock, conversion basis (in shares)					1
Operating Company Units \| Repurchase Program
Class of Stock [Line Items]
Amount of shares repurchased					$ 41,000,000
Repurchased shares (in shares)					1,000,000

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Oil and natural gas interests:
Proved	$ 9,746	$ 3,533
Unproved	4,910	2,180
Total oil and natural gas interests	14,656	5,713
Accumulated depletion	(1,567)	(961)
Accumulated impairment	(888)	(120)
Net oil and natural gas interests capitalized	$ 12,201	$ 4,632

SUBSEQUENT EVENTS (Details) $ / shares in Units, $ in Millions	Feb. 18, 2026 USD ($) $ / shares	Feb. 09, 2026 USD ($) a bbl	Feb. 20, 2026 USD ($)	Dec. 31, 2025 USD ($)
Repurchase Program
Subsequent Event [Line Items]
Authorized amount in repurchase program				$ 750
Subsequent Event
Subsequent Event [Line Items]
Remaining authorized repurchase amount			$ 1,200
Subsequent Event \| Unsecured Debt \| Term Loan \| Line of Credit
Subsequent Event [Line Items]
Amount outstanding under credit facility		$ 500
Subsequent Event \| Revolving credit facility \| Revolving Credit Facility, 2025 \| Line of Credit
Subsequent Event [Line Items]
Amount outstanding under credit facility		90
Subsequent Event \| Disposal Group, Disposed of by Sale, Not Discontinued Operations \| Divestiture of Non-Permian Assets
Subsequent Event [Line Items]
Proceeds from sale of acres		$ 617
Number of net royalty acres \| a		9,400
Daily oil production (in barrels) \| bbl		4,750
Subsequent Event \| Repurchase Program
Subsequent Event [Line Items]
Authorized amount in repurchase program	$ 1,750
Common Class A \| Repurchase Program
Subsequent Event [Line Items]
Remaining authorized repurchase amount				$ 241
Common Class A \| Subsequent Event \| O 2026 A Dividends
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares	$ 1.52
Common Class A \| Subsequent Event \| O 2025 Q4 Dividends
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares	0.52
Common Class A \| Subsequent Event \| O 2025 Q4 Base Dividends
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares	0.38
Common Class A \| Subsequent Event \| O 2025 Q4 Variable Dividends
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares	0.14
Operating Company Units \| Subsequent Event
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares	$ 0.65

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Proved Undeveloped Reserves (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2025 MBoe
Proved Undeveloped Reserves (Energy)
Beginning proved undeveloped reserves (in MBOE)	32,009
Undeveloped reserves transferred to developed (in MBOE)	(11,848)
Revisions (in MBOE)	5,643
Purchases (in MBOE)	28,395
Extensions and discoveries (in MBOE)	46,420
Ending proved undeveloped reserves (in MBOE)	89,333

DERIVATIVES - Schedule of Open Derivative Positions (Details) bbl in Thousands, MMBTU in Thousands	12 Months Ended
	Dec. 31, 2025 MMBTU $ / bbl $ / MMBTU bbl
OIL \| WTI Cushing \| Puts \| 2026 \| Jan. - Mar.
Derivative [Line Items]
Bbls Per Day (in Bbls) \| bbl	40
Weighted Average Differential (usd per bbls) \| $ / bbl	0
Weighted Average Floor Price (usd per bbls/mmbtu) \| $ / bbl	0
Weighted Average Ceiling Price (usd per bbls/mmbtu) \| $ / bbl	0
Strike Price (usd per bbls/mmbtu) \| $ / bbl	51.75
Deferred Premium (usd per bbls/mmbtu) \| $ / bbl	(1.56)
OIL \| WTI Cushing \| Puts \| 2026 \| Apr. - Jun.
Derivative [Line Items]
Bbls Per Day (in Bbls) \| bbl	20
Weighted Average Differential (usd per bbls) \| $ / bbl	0
Weighted Average Floor Price (usd per bbls/mmbtu) \| $ / bbl	0
Weighted Average Ceiling Price (usd per bbls/mmbtu) \| $ / bbl	0
Strike Price (usd per bbls/mmbtu) \| $ / bbl	48.13
Deferred Premium (usd per bbls/mmbtu) \| $ / bbl	(1.35)
NATURAL GAS \| Waha Hub \| Basis Swaps \| 2026 \| Jan. - Dec.
Derivative [Line Items]
MMBtu Per Day (in mmbtu) \| MMBTU	80
Weighted Average Differential (usd per bbls)	(1.61)
Weighted Average Floor Price (usd per bbls/mmbtu)	0
Weighted Average Ceiling Price (usd per bbls/mmbtu)	0
Strike Price (usd per bbls/mmbtu)	0
Deferred Premium (usd per bbls/mmbtu)	0
NATURAL GAS \| Waha Hub \| Basis Swaps \| 2027 \| Jan. - Dec.
Derivative [Line Items]
MMBtu Per Day (in mmbtu) \| MMBTU	40
Weighted Average Differential (usd per bbls)	(1.40)
Weighted Average Floor Price (usd per bbls/mmbtu)	0
Weighted Average Ceiling Price (usd per bbls/mmbtu)	0
Strike Price (usd per bbls/mmbtu)	0
Deferred Premium (usd per bbls/mmbtu)	0
NATURAL GAS \| Henry Hub \| Costless Collar \| 2026 \| Jan. - Dec.
Derivative [Line Items]
MMBtu Per Day (in mmbtu) \| MMBTU	60
Weighted Average Differential (usd per bbls)	0
Weighted Average Floor Price (usd per bbls/mmbtu)	2.75
Weighted Average Ceiling Price (usd per bbls/mmbtu)	6.64
Strike Price (usd per bbls/mmbtu)	0
Deferred Premium (usd per bbls/mmbtu)	0

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Interest or penalties associated with uncertain tax positions	$ 0	$ 0	$ 0

SEGMENT INFORMATION (Details)	12 Months Ended
SEGMENT INFORMATION (Details)	Dec. 31, 2025 segment
Segment Reporting [Abstract]
Number of reportable segments	1
Number of operating segments	1

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Audit Information [Abstract]
Auditor Firm ID	248
Auditor Name	GRANT THORNTON LLP
Auditor Location	Oklahoma City, Oklahoma

OIL AND NATURAL GAS INTERESTS (Tables)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

Schedule of Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities

Oil and natural gas interests include the following for the periods presented:


	December 31,
	2025		2024
	(In millions)
Oil and natural gas interests:
Proved properties	$	9,746	$	3,533
Unproved properties	4,910		2,180
Gross oil and natural gas interests	14,656		5,713
Accumulated depletion	(1,567)		(961)
Accumulated impairment	(888)		(120)
Oil and natural gas interests, net	12,201		4,632
Other property, equipment and land	8		6
Property, net of accumulated depletion and impairment	$	12,209	$	4,638

Balance of costs not subject to depletion:
Incurred in 2025	$	3,614
Incurred in 2024	562
Incurred in 2023	553
Prior	181
Total not subject to depletion	$	4,910

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


	December 31,
	2025		2024
	(In millions)
Oil and natural gas interests:
Proved	$	9,746	$	3,533
Unproved	4,910		2,180
Total oil and natural gas interests	14,656		5,713
Accumulated depletion	(1,567)		(961)
Accumulated impairment	(888)		(120)
Net oil and natural gas interests capitalized	$	12,201	$	4,632

REVENUE FROM CONTRACTS WITH CUSTOMERS

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

REVENUE FROM CONTRACTS WITH CUSTOMERS

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained from third-party purchasers by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index.

For the years ended December 31, 2025, 2024 and 2023, any revenues recognized in the current reporting period for performance obligations satisfied in prior reporting periods were not material.

The following tables disaggregate the Company’s revenue from oil, natural gas and natural gas liquids by revenue generated from production on properties operated by Diamondback and revenue generated from production on properties operated by third parties:


	Year Ended December 31, 2025
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	612	$	519	$	1,131
Natural gas income	31		25		56
Natural gas liquids income	98		61		159
Total royalty income	$	741	$	605	$	1,346


	Year Ended December 31, 2024
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	398	$	352	$	750
Natural gas income	10		5		15
Natural gas liquids income	51		38		89
Total royalty income	$	459	$	395	$	854


	Year Ended December 31, 2023
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	377	$	242	$	619
Natural gas income	16		15		31
Natural gas liquids income	42		25		67
Total royalty income	$	435	$	282	$	717

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-7

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
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+ Details

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2025
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Cash Dividend On February 18, 2026, our board of directors approved an increase to the Company’s annual base dividend to $1.52 per share of Class A Common Stock beginning with the dividend payable for the fourth quarter of 2025. Our board of directors further approved a cash dividend for the fourth quarter of 2025 of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit, in each case, payable on March 12, 2026, to holders of record at the close of business on March 5, 2026. The dividend on Class A Common Stock consists of a base quarterly dividend of $0.38 per share and a variable quarterly dividend of $0.14 per share. Increase in Repurchase Program Authorization On February 18, 2026, our board of directors approved an increase in authorization under the Company’s existing repurchase program from $750 million to $1.75 billion, excluding excise tax. As of February 20, 2026, approximately $1.2 billion remains available for future repurchases under our repurchase program, excluding excise tax. Divestiture of Non-Permian Assets On February 9, 2026, the Company divested all of its non-Permian assets, including those acquired from Sitio, to an affiliate of GRP Energy Capital LLC and Warwick Capital Partners LLP for net cash proceeds of approximately $617 million, subject to customary post-closing adjustments. The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d. Proceeds from the divestiture were used to (i) repay the Company’s $500 million Term Loan in full, (ii) fully repay $90 million of then-outstanding borrowings under the 2025 Revolving Credit Facility, and (iii) for general corporate purposes.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue from Contracts with Customers, Oil and Natural Gas Properties, Royalty Income Receivable, Concentrations and Related Party Transactions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) a lease $ / Boe	Dec. 31, 2024 USD ($) $ / Boe	Dec. 31, 2023 USD ($) a lease leaseExtension $ / Boe
Debt Instrument [Line Items]
Depletion	$ 607	$ 214	$ 146
Estimated future net revenue discounted rate per annum	10.00%
Royalty income receivable, expected payment period	3 months
Related Party
Debt Instrument [Line Items]
Royalty income receivable	$ 88	31
Lease bonus income	$ 24	0	108
Number of new leases \| lease	18
Area of lease land \| a	2,356
Related Party \| Midland County, Texas
Debt Instrument [Line Items]
Lease bonus income			$ 96
Number of new leases \| lease			1
Related Party \| Martin, Midland, Pecos, and Wheelers Counties, Texas
Debt Instrument [Line Items]
Number of new leases \| lease			9
Area of lease land \| a			703
Related Party \| Martin County, Texas
Debt Instrument [Line Items]
Area of lease land \| a			25
Number of lease extensions \| leaseExtension			2
Royalty Income Receivable \| Affiliated Entity
Debt Instrument [Line Items]
Royalty income receivable	$ 88	$ 31
Diamondback Energy, Inc. \| Royalty Interest Revenue \| Customer Concentration Risk
Debt Instrument [Line Items]
Percent of total royalty interest revenue	55.00%	54.00%	61.00%
ExxonMobil Corporation \| Royalty Interest Revenue \| Customer Concentration Risk
Debt Instrument [Line Items]
Percent of total royalty interest revenue	14.00%
Pioneer Natural Resources \| Royalty Interest Revenue \| Customer Concentration Risk
Debt Instrument [Line Items]
Percent of total royalty interest revenue		11.00%
Oil and Gas Properties
Debt Instrument [Line Items]
Average depletion rate per barrel equivalent unit of production (usd per BOE) \| $ / Boe	17.48	11.77	10.20
Depletion	$ 607	$ 214	$ 146
Minimum
Debt Instrument [Line Items]
Settlement statements received, after production delivered, period	30 days
Maximum
Debt Instrument [Line Items]
Settlement statements received, after production delivered, period	90 days

STOCKHOLDERS’ EQUITY - Schedule of Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Dec. 31, 2025	Sep. 30, 2025	Jun. 30, 2025	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023
Diamondback Energy, Inc.
Class of Stock [Line Items]
Limited partners' capital account, units outstanding (in shares)									731,500
Common Class A
Class of Stock [Line Items]
Common stock outstanding (in shares)	170,942,687				102,977,142
Common Class A \| Diamondback Energy, Inc.
Class of Stock [Line Items]
Common stock outstanding (in shares)								7,946,507
Cash Distribution \| Operating Company Units
Class of Stock [Line Items]
Amount per Operating Company Unit/Amount per Common Share (usd per share)	$ 0.66	$ 0.59	$ 0.70	$ 0.69	$ 0.73	$ 0.76	$ 0.70	$ 0.69	$ 0.70	$ 0.44	$ 0.42	$ 0.54
Operating Company Distributions to Diamondback/Common Unitholders	$ 134	$ 98	$ 117	$ 68	$ 69	$ 65	$ 60	$ 63	$ 64	$ 40	$ 38	$ 49
Cash Distribution \| Common Class A
Class of Stock [Line Items]
Amount per Operating Company Unit/Amount per Common Share (usd per share)	$ 0.58	$ 0.53	$ 0.57	$ 0.65	$ 0.61	$ 0.64	$ 0.59	$ 0.56	$ 0.57	$ 0.36	$ 0.33	$ 0.49
Operating Company Distributions to Diamondback/Common Unitholders	$ 99	$ 68	$ 75	$ 85	$ 63	$ 59	$ 54	$ 48	$ 49	$ 25	$ 24	$ 36

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(2)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

+ Details

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Components of the Provision for Income Taxes

The components of the provision for income taxes for the years ended December 31, 2025, 2024 and 2023 are as follows:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Current income tax provision (benefit):
Federal	$	60	$	47	$	50
State	4		2		3
Total current income tax provision (benefit)	64		49		53
Deferred income tax provision (benefit):
Federal	(78)		(148)		(7)
State	(5)		(1)		—
Total deferred income tax provision (benefit)	(83)		(149)		(7)
Total provision (benefit) from income taxes	$	(19)	$	(100)	$	46

Schedule of Reconciliation of the Statutory Federal Income Tax

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:


	Year Ended December 31,
	2025				2024				2023
	Amount (In millions)		Percentage of Income (Loss) Before Income Taxes		Amount (In millions)		Percentage of Income (Loss) Before Income Taxes		Amount (In millions)		Percentage of Income (Loss) Before Income Taxes
Income tax expense (benefit) at the federal statutory rate (21%)	$	(47)	21	%	$	106	21	%	$	115	21	%


State income tax, net of federal income tax effect(1)	(1)		—	%	2		—	%	2		—	%


Changes in valuation allowances	—		—	%	(156)		(31)	%	(8)		(1)	%

Nontaxable or nondeductible items:
Impact of nontaxable noncontrolling interest	29		(13)	%	(52)		(10)	%	(63)		(12)	%
Provision for (benefit from) income taxes	$	(19)	8	%	$	(100)	(20)	%	$	46	8	%

(1)State taxes in Texas make up the majority (greater than 50%) of the tax effect in this category.

Schedule of Deferred Tax Assets and Liabilities

The components of the Company’s deferred tax assets and liabilities as of December 31, 2025 and 2024 are as follows:


	Year Ended December 31,
	2025		2024
	(In millions)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	5	$	—
Investment in the Operating Company	28		185


Total deferred tax assets	33		185
Valuation allowance	—		—
Net deferred tax assets	33		185




Net deferred tax assets (liabilities)	$	33	$	185

STOCKHOLDERS’ EQUITY

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

STOCKHOLDERS’ EQUITY

At December 31, 2025, the Company had a total of 170,942,687 shares of Class A Common Stock issued and outstanding and 187,023,698 shares of Class B Common Stock issued and outstanding. Additionally, at December 31, 2025, TWR IV held the TWR Class B Option to acquire up to 10,093,670 shares of the Company’s Class B Common Stock.

In connection with the Reorganization, Viper in its position as managing member of New OpCo, along with affiliates of Diamondback, TWR IV and the Morita Ranches Equity Recipients adopted the Amended and Restated Limited Liability Company Agreement of New OpCo (the “New OpCo LLC Agreement”). The New OpCo LLC Agreement provides that members of New OpCo may require the Company to redeem all or a portion of the shares of the Company’s Class B Common Stock held by such member, together with an equal number of OpCo Units (one share of Class B Common Stock together with one OpCo Unit) in exchange for (i) an equivalent number of shares of the Company’s Class A Common Stock, or (ii) cash consideration subject to the terms and conditions included in the New OpCo LLC Agreement.

The following table presents the beneficial ownership of Common Stock and OpCo Units as of December 31, 2025:


	As of December 31, 2025
	Shares of Common Stock Beneficially Owned	Percentage Ownership(1)		OpCo Units Beneficially Owned	Percentage Ownership
Public equity holders of Class A Common Stock	170,942,687	46.5	%	—	—	%
Viper and subsidiaries	—	—	%	170,942,687	46.5	%
Diamondback and subsidiaries	155,058,093	42.1	%	155,058,093	42.1	%
Sitio OpCo former equity holders	29,565,308	8.0	%	29,565,308	8.0	%
TWR IV(1)	10,093,670	2.7	%	10,093,670	2.7	%
Morita Ranches Equity Recipients	2,400,297	0.7	%	2,400,297	0.7	%
Total Ownership(1)	368,060,055	100.0	%	368,060,055	100.0	%

(1)On a fully diluted basis, assuming TWR IV exercises the TWR Class B Option.

2025 Equity Offering

On February 3, 2025, the Company completed an underwritten public offering of 28,336,000 shares of Class A Common Stock, which included 3,696,000 shares issued pursuant to an option to purchase additional shares of Class A Common Stock granted to the underwriters, at a price to the public of $44.50 per share for total net proceeds of approximately $1.2 billion, after the underwriters’ discount and transaction costs (the “2025 Equity Offering”). The Company used the net proceeds from the 2025 Equity Offering to fund (i) the cash consideration for the Morita Ranches Acquisition, (ii) a portion of the cash consideration for the 2025 Drop Down, and (iii) for general corporate purposes.

2024 Equity Offering

On September 13, 2024, the Company completed an underwritten public offering of 11,500,000 shares of Class A Common Stock, which included 1,500,000 shares issued pursuant to an option to purchase additional shares of Class A Common Stock granted to the underwriters, at a price to the public of $42.50 per share for total net proceeds of approximately $476 million, after the underwriters’ discount and transaction costs (the “2024 Equity Offering”). The net proceeds were used to fund a portion of the cash consideration for the TWR Acquisition.

2023 Viper Issuance of Common Units to Diamondback

In October 2023, the Company issued 7,215,007 of its common units to Diamondback at a price of $27.72 per unit for total net proceeds of approximately $200 million. The net proceeds were used to fund a portion of the cash consideration for the GRP Acquisition. During 2024, Diamondback sold all of its shares of the Company’s Class A Common Stock in the Diamondback Offering discussed in Note 1—Organization and Basis of Presentation.

Repurchase Program

Previously, the Company’s board of directors authorized a $750 million repurchase program, with respect to the repurchase of the Company’s Class A Common Stock, excluding excise tax, over an indefinite period of time. On December 10, 2025, the Company’s board of directors expanded the repurchase program to also include repurchases of the Company’s Class B Common Stock and OpCo Units. The Company has purchased and intends to continue to purchase shares of Common Stock and OpCo Units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. This repurchase program may be suspended, modified or extended, from time to time, or may be discontinued at any time, in each case, by the Company’s board of directors.

During the year ended December 31, 2025, repurchases under the repurchase program totaled $194 million, which includes approximately $41 million for the repurchase of 1,000,000 OpCo Units from an affiliate of Kimmeridge Energy Management Company, LLC (“Kimmeridge”) in a privately negotiated transaction on December 10, 2025. Concurrently, a corresponding number of shares of the Company’s Class B Common Stock owned by Kimmeridge were cancelled. During the year ended December 31, 2024, there were no repurchases under the repurchase program. Repurchases of $95 million for the year ended December 31, 2023, include approximately $29 million for the repurchase of 1,000,000 shares of Class A Common Stock from GRP in a privately negotiated transaction in the fourth quarter of 2023. As of December 31, 2025, $241 million remains available under the repurchase program, excluding excise tax.

Cash Dividends

The board of directors of the Company has established a dividend policy, whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to holders of the OpCo Units. Viper in turn distributes all or a portion of the available cash it receives from the Operating Company to holders of its Class A Common Stock through base and variable dividends that take into account capital returned to stockholders via its repurchase program. The Company’s available cash and the available cash of the Operating Company for each quarter is determined by the board of directors following the end of such quarter. The Company’s dividend policy currently requires the Company to pay quarterly variable dividends of at least 75% of its available cash less the base dividend declared and the amount paid for repurchases of the Company’s Common Stock and OpCo Units as part of its repurchase program for the applicable quarter. Additionally, the Company’s board of directors may approve certain one-time discretionary adjustments to the calculation of cash available for distribution.

The Company expects that its available cash will generally equal the Adjusted EBITDA attributable to the Company for the applicable quarter, less cash needed for income taxes payable; debt service, contractual obligations, fixed charges and reserves for future operating or capital needs that the Company’s board of directors deems necessary or appropriate; lease bonus income (net of applicable taxes); dividend equivalent rights payments; preferred distributions and an adjustment for changes in ownership interests that occurred subsequent to the quarter, if any.

The percentage of cash available for distribution by the Operating Company pursuant to the distribution policy may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Company’s balance sheet while also expanding the return of capital program through the Company’s repurchase program. The Company is not required to pay dividends to the holders of its Class A Common Stock on a quarterly or other basis.

The Company is also required to pay a quarterly preferred dividend in respect of its Class B Common Stock in the aggregate amount of $20,000 per quarter, which is consistent with the Partnership’s pre-Conversion preferred distribution requirement. Other than the preferred dividend requirement, the Company is not required to pay dividends to the holders of its Common Stock on a quarterly or other basis, and declaration of any other dividends in the future will be solely in the discretion of the Company’s board of directors.

The following table presents information regarding cash distributions and dividends paid during the years ended December 31, 2025, 2024 and 2023 (in millions except per share amounts):


	Distributions
Period	Amount per OpCo Unit		Operating Company Distributions to Non-Controlling Interests		Amount per Class A Common Share		Class A Common Stockholders(1)(2)		Declaration Date	Class A Common Stockholder Record Date	Payment Date
2025
Q4 2024	$	0.69	$	68	$	0.65	$	85	January 30, 2025	March 6, 2025	March 13, 2025
Q1 2025	$	0.70	$	117	$	0.57	$	75	May 1, 2025	May 15, 2025	May 22, 2025
Q2 2025	$	0.59	$	98	$	0.53	$	68	July 31, 2025	August 14, 2025	August 21, 2025
Q3 2025	$	0.66	$	134	$	0.58	$	99	October 30, 2025	November 13, 2025	November 20, 2025
2024
Q4 2023	$	0.69	$	63	$	0.56	$	48	February 15, 2024	March 5, 2024	March 12, 2024
Q1 2024	$	0.70	$	60	$	0.59	$	54	April 25, 2024	May 15, 2024	May 22, 2024
Q2 2024	$	0.76	$	65	$	0.64	$	59	August 1, 2024	August 15, 2024	August 22, 2024
Q3 2024	$	0.73	$	69	$	0.61	$	63	October 31, 2024	November 14, 2024	November 21, 2024
2023
Q4 2022	$	0.54	$	49	$	0.49	$	36	February 15, 2023	March 3, 2023	March 10, 2023
Q1 2023	$	0.42	$	38	$	0.33	$	24	April 26, 2023	May 11, 2023	May 18, 2023
Q2 2023	$	0.44	$	40	$	0.36	$	25	July 25, 2023	August 10, 2023	August 17, 2023
Q3 2023	$	0.70	$	64	$	0.57	$	49	November 2, 2023	November 16, 2023	November 24, 2023

(2)For distributions paid in 2023, includes amounts paid to Diamondback for the 731,500 common units then beneficially owned by Diamondback.

Cash dividends will be made to the holders of record of the Company’s Class A Common Stock on the applicable record date, generally within 60 days after the end of each quarter.

Changes in Ownership of Consolidated Subsidiaries

Non-controlling interest in the accompanying consolidated financial statements represents the ownership interests of Diamondback, Sitio OpCo’s former equity holders, TWR IV and the Morita Ranches Equity Recipients in the net assets of the Operating Company. The non-controlling interests’ relative ownership in the Operating Company can change due to the purchase or sale of the Company’s Common Stock, the Company’s public offerings of shares of Class A Common Stock for which proceeds are contributed to the Operating Company in exchange for OpCo Units, issuance of shares of Class A Common Stock or issuance of shares of Class B Common Stock and OpCo Units for acquisitions, share-based compensation, repurchases of shares of Common Stock or OpCo Units and dividend equivalent rights paid on the Company’s Class A Common Stock. These changes in ownership percentage result in adjustments to non-controlling interest and stockholders’ equity, tax effected, but do not impact earnings.

The following table summarizes the changes in stockholders’ equity due to changes in ownership interest during the period:


	Year Ended December 31,
	2025		2024		2023
	(In millions)
Net income (loss) attributable to the Company	$	(68)	$	359	$	200
Change in ownership of consolidated subsidiaries	448		59		(102)
Change from net income (loss) attributable to the Company’s stockholders and transfers with non-controlling interest	$	380	$	418	$	98

- Definition

The entire disclosure for equity.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-14

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477968/946-235-50-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 235
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477968/946-235-50-2

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 505
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478448/946-505-50-6

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 40
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480237/815-40-50-6

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480008/505-10-S99-1

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/505/tableOfContent

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-14

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Name Accounting Standards Codification
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-18

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
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-Paragraph 18
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-18

+ Details

DERIVATIVES - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Gain (loss) on derivative instruments, net	$ 44	$ 11	$ (26)
Treasury locks
Derivative [Line Items]
Gain (loss) on derivative instruments, net	$ 3

OIL AND NATURAL GAS INTERESTS - Schedule of Aggregate Capitalized Costs Related to Oil and Natural Gas Production Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Extractive Industries [Abstract]
Proved	$ 9,746	$ 3,533
Unproved	4,910	2,180
Total oil and natural gas interests	14,656	5,713
Accumulated depletion	(1,567)	(961)
Accumulated impairment	(888)	(120)
Net oil and natural gas interests capitalized	12,201	4,632
Other property, equipment and land	8	6
Property, net	12,209	4,638
Balance of costs not subject to depletion:	3,614	$ 562	$ 553	$ 181
Total not subject to depletion	$ 4,910

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Average First-Day-of-the-Month Price for Oil, Natural Gas and Natural Gas Liquids (Details)	12 Months Ended
	Dec. 31, 2025 $ / bbl $ / Mcf	Dec. 31, 2024 $ / bbl $ / Mcf	Dec. 31, 2023 $ / bbl $ / Mcf
Crude Oil, Condensate, and Natural Gas Liquids (NGL)
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per unit)	64.80	75.61	77.93
Natural Gas
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per unit) \| $ / Mcf	1.31	0.49	1.54
Natural Gas Liquids
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per unit)	18.95	20.62	23.79

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Current assets:
Cash and cash equivalents	$ 13	$ 27
Prepaid expenses and other current assets	50	31
Total current assets	413	238
Oil and natural gas properties:
Proved properties	9,746	3,533
Unproved properties	4,910	2,180
Other property, equipment and land	8	6
Accumulated depletion and impairment	(2,455)	(1,081)
Property, net	12,209	4,638
Deferred income taxes (net of allowances)	33	185
Other assets	16	8
Total assets	12,671	5,069
Current liabilities:
Accrued liabilities	107	43
Other current liabilities	4	6
Total current liabilities	111	49
Long-term debt, net	2,186	1,083
Other long-term liabilities	11	30
Total liabilities	2,308	1,162
Commitments and contingencies (Note 12)
Stockholders’ equity:
Additional paid-in capital	4,726	1,569
Retained earnings (accumulated deficit)	(278)	118
Total Viper Energy, Inc. stockholders’ equity	4,448	1,687
Non-controlling interest	5,915	2,220
Total equity	10,363	3,907
Total liabilities and stockholders’ equity	12,671	5,069
Common Class A
Stockholders’ equity:
Common Stock	0	0
Common Class B
Stockholders’ equity:
Common Stock	0	0
Nonrelated Party
Current assets:
Royalty income receivable	262	149
Related Party
Current assets:
Royalty income receivable	$ 88	$ 31

DERIVATIVES - Schedule of Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Gain (loss) on derivative instruments, net:	$ 44	$ 11	$ (26)
Net cash receipts (payments) on derivatives:	30	(3)	(13)
Commodity contracts
Derivative [Line Items]
Gain (loss) on derivative instruments, net:	31	15	(26)
Net cash receipts (payments) on derivatives:	27	(3)	(13)
2026 WTI Contingent Liability
Derivative [Line Items]
Gain (loss) on derivative instruments, net:	10	(4)	0
Treasury locks
Derivative [Line Items]
Gain (loss) on derivative instruments, net:	3	0	0
Net cash receipts (payments) on derivatives:	$ 3	$ 0	$ 0

ACQUISITIONS AND DIVESTITURES (Details)								1 Months Ended		3 Months Ended	6 Months Ended	12 Months Ended
ACQUISITIONS AND DIVESTITURES (Details)	Aug. 19, 2025 USD ($) a $ / shares shares	May 01, 2025 USD ($) a well shares bbl	Feb. 14, 2025 USD ($) a shares	Oct. 01, 2024 USD ($) a $ / bbl shares	Sep. 03, 2024 USD ($) a $ / bbl	Nov. 01, 2023 USD ($) a shares	Mar. 08, 2023 USD ($) a bbl	Jan. 31, 2026 USD ($)	Oct. 31, 2023 USD ($)	Jun. 30, 2024 USD ($) a bbl	Dec. 31, 2025 USD ($) a $ / shares	Dec. 31, 2025 USD ($) a $ / shares	Dec. 31, 2024 USD ($) a $ / shares	Dec. 31, 2023 USD ($) a
2023 Viper Issuance of Common Units to Diamondback
Business Combination [Line Items]
Sale of stock, consideration received on transaction									$ 200,000,000
Discontinued Operations, Disposed of by Sale \| Divestiture of Non-Permian Assets
Business Combination [Line Items]
Daily oil production (in barrels) \| bbl										450
Proceeds from sale of acres										$ 87,000,000
Area of land, net (acres) \| a										2,713
Disposal group, not discontinued operation, gain (loss) on disposal										$ 0
Common Class A
Business Combination [Line Items]
Common stock par value (usd per share) \| $ / shares											$ 0.000001	$ 0.000001	$ 0.000001
Common Class B
Business Combination [Line Items]
Common stock par value (usd per share) \| $ / shares											$ 0.000001	$ 0.000001	$ 0.000001
Sitio Acquisition
Business Combination [Line Items]
Asset acquisition, consideration transferred, equity interest issued and issuable	$ 4,000,000,000.0
Asset acquisition, acquiree retirement of debt	$ 1,200,000,000
Number of net royalty acres \| a	34,300
Sitio Acquisition \| Common Class A
Business Combination [Line Items]
Asset acquisition, number of shares converted from each share \| shares	0.4855
Asset acquisition, number of shares upon conversion \| shares	1
Equity interest issued (in shares) \| shares	38,536,236
Sitio Acquisition \| Sitio Class A Common Stock
Business Combination [Line Items]
Common stock par value (usd per share) \| $ / shares	$ 0.0001
Sitio Acquisition \| Common Class B
Business Combination [Line Items]
Asset acquisition, number of shares converted from each share \| shares	0.4855
Asset acquisition, number of shares called for conversion \| shares	1
Equity interest issued (in shares) \| shares	35,619,951
Sitio Acquisition \| Operating Company Units
Business Combination [Line Items]
Asset acquisition, number of shares converted from each share \| shares	0.4855
Asset acquisition, number of units called for conversion (in shares) \| shares	1
Equity interest issued (in shares) \| shares	35,619,951
Sitio Acquisition \| Sitio Class C Common Stock
Business Combination [Line Items]
Common stock par value (usd per share) \| $ / shares	$ 0.0001
Sitio Acquisition, Permian Basin
Business Combination [Line Items]
Number of net royalty acres \| a	25,300
Sitio Acquisition, Denver-Julesburg, Eagle Ford And Williston Basins
Business Combination [Line Items]
Number of net royalty acres \| a	9,000
Endeavor Subsidiaries
Business Combination [Line Items]
Number of net royalty acres \| a		24,446
Consideration transferred		$ 873,000,000
Average net royalty interest		2.20%
Daily oil production (in barrels) \| bbl		17,097
Asset acquisition, proved developed production, number of wells, gross \| well		5,574
Asset acquisition, completed production, number of wells, gross \| well		116
Asset acquisition, uncompleted production well, number of wells, gross \| well		394
Endeavor Subsidiaries \| Diamondback Energy, Inc.
Business Combination [Line Items]
Percentage of acreage operated by beneficial interest holder		69.00%
Percentage of wells operated by beneficial interest holder		32.00%
Endeavor Subsidiaries \| Common Class A
Business Combination [Line Items]
Asset acquisition, number of shares upon conversion \| shares		1
Endeavor Subsidiaries \| Common Class B
Business Combination [Line Items]
Asset acquisition, number of shares called for conversion \| shares		1
Endeavor Subsidiaries \| Operating Company Units
Business Combination [Line Items]
Asset acquisition, number of units called for conversion (in shares) \| shares		1
Equity interest issued (in shares) \| shares		69,626,640
Morita Ranches
Business Combination [Line Items]
Number of net royalty acres \| a			1,691
Consideration transferred			$ 208,000,000
Average net royalty interest			10.90%
Morita Ranches \| Diamondback Energy, Inc.
Business Combination [Line Items]
Percentage of acreage operated by beneficial interest holder			75.00%
Morita Ranches \| Common Class B
Business Combination [Line Items]
Equity interest issued (in shares) \| shares			2,400,297
Morita Ranches \| Operating Company Units
Business Combination [Line Items]
Equity interest issued (in shares) \| shares			2,400,297
2025 Permian Basin Acquisition \| Unrelated Third-Party Sellers
Business Combination [Line Items]
Number of net royalty acres \| a												515
Consideration transferred												$ 140,000,000
2025 Permian Basin Acquisition \| Diamondback E&P LLC
Business Combination [Line Items]
Number of net royalty acres \| a											80
Consideration transferred											$ 2,000,000
TWR Acquisition
Business Combination [Line Items]
Number of net royalty acres \| a				3,067
Royalty income receivable				$ 24,000,000
TWR Acquisition \| TWR IV
Business Combination [Line Items]
Consideration transferred				$ 464,000,000
TWR Acquisition \| TWR IV \| Subsequent Event
Business Combination [Line Items]
Contingent consideration, paid								$ 16,000,000
TWR Acquisition \| TWR IV \| Minimum
Business Combination [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per barrel) \| $ / bbl				60.00
TWR Acquisition \| TWR IV \| Maximum
Business Combination [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per barrel) \| $ / bbl				65.00
TWR Acquisition \| Common Class B \| TWR IV
Business Combination [Line Items]
Asset acquisition, option granted to acquire common stock, shares (in shares) \| shares				10,093,670
TWR Acquisition \| Operating Company Units \| TWR IV
Business Combination [Line Items]
Equity interest issued (in shares) \| shares				10,093,670
Q Acquisitions
Business Combination [Line Items]
Number of net royalty acres \| a					406
Q Acquisitions \| Tumbleweed-Q Royalties, LLC
Business Combination [Line Items]
Consideration transferred					$ 114,000,000
Q Acquisitions \| Tumbleweed-Q Royalties, LLC \| Subsequent Event
Business Combination [Line Items]
Contingent consideration, paid								2,000,000
Q Acquisitions \| Tumbleweed-Q Royalties, LLC \| Minimum
Business Combination [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per barrel) \| $ / bbl					60.00
Q Acquisitions \| Tumbleweed-Q Royalties, LLC \| Maximum
Business Combination [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per barrel) \| $ / bbl					65.00
M Acquisitions
Business Combination [Line Items]
Number of net royalty acres \| a					267
M Acquisitions \| MC TWR Royalties, LP and MC TWR Intermediate, LLC
Business Combination [Line Items]
Consideration transferred					$ 76,000,000
M Acquisitions \| MC TWR Royalties, LP and MC TWR Intermediate, LLC \| Subsequent Event
Business Combination [Line Items]
Contingent consideration, paid								$ 2,000,000
M Acquisitions \| MC TWR Royalties, LP and MC TWR Intermediate, LLC \| Minimum
Business Combination [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per barrel) \| $ / bbl					60.00
M Acquisitions \| MC TWR Royalties, LP and MC TWR Intermediate, LLC \| Maximum
Business Combination [Line Items]
Unweighted arithmetic average first-day-of-the-month prices (usd per barrel) \| $ / bbl					65.00
2024 Permian Basin Acquisition \| Unrelated Third-Party Sellers
Business Combination [Line Items]
Number of net royalty acres \| a													261
Consideration transferred													$ 54,000,000
GRP Acquisition
Business Combination [Line Items]
Consideration transferred						$ 747,000,000
GRP Acquisition \| Common Class A
Business Combination [Line Items]
Equity interest issued (in shares) \| shares						9,018,760
GRP Acquisition, Permian Basin
Business Combination [Line Items]
Number of net royalty acres \| a						4,600
GRP Acquisition, Other Major Basin
Business Combination [Line Items]
Number of net royalty acres \| a						2,700
2023 Drop Down
Business Combination [Line Items]
Number of net royalty acres \| a							660
Consideration transferred							$ 75,000,000
Average net royalty interest							7.20%
Daily oil production (in barrels) \| bbl							300
Percentage of acreage acquired							100.00%
2023 Acquisition Permian Basin \| Unrelated Third-Party Sellers
Business Combination [Line Items]
Number of net royalty acres \| a														286
Consideration transferred														$ 70,000,000

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Accounting Policies [Abstract]
Interest payable	$ 39	$ 10
Ad valorem taxes payable	34	20
Acquisition adjustment accrual	4	9
2026 WTI Contingent Liability	20	0
Other	10	4
Total accrued liabilities	$ 107	$ 43

ORGANIZATION AND BASIS OF PRESENTATION (Details)			12 Months Ended
ORGANIZATION AND BASIS OF PRESENTATION (Details)	Mar. 08, 2024 shares	Nov. 13, 2023 director shares	Dec. 31, 2025 segment $ / shares	Feb. 25, 2026	Aug. 19, 2025 $ / shares shares	Dec. 31, 2024 $ / shares	Nov. 12, 2023
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Ownership percentage by general partner							100.00%
Shares converted (in shares) \| shares		1
Designated board members (up to) \| director		2
Number of reportable segments \| segment			1
Minimum
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Voting power to change board designations		80.00%
Minimum \| Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Ownership percentage by parent		25.00%
Maximum
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Designated board members (up to) \| director		3
Viper Energy Inc. \| Diamondback Energy, Inc.
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Ownership percentage by parent	50.00%
Viper Energy Inc. \| Diamondback Energy, Inc. \| Subsequent Event
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Ownership percentage				50.00%
Operating Company Units
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Shares converted (in shares) \| shares		1
Operating Company Units \| VNOM Holding Company LLC
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Ownership by counterparty, percent			100.00%
Operating Company Units \| VNOM Holding Company LLC \| Viper and subsidiaries
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Ownership by counterparty, percent			46.50%
Common Class A
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Common stock par value (usd per share)			$ 0.000001			$ 0.000001
Common Class A \| Diamondback Offering \| Diamondback Energy, Inc.
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Number of shares sold \| shares	13,225,000
Common Class B
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Common stock par value (usd per share)			$ 0.000001			$ 0.000001
Common Class B \| Viper Energy Inc. \| Diamondback Energy, Inc.
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Ownership percentage			42.10%
Sitio Acquisition, Viper Pubco Merger \| New Viper Class A Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Common stock par value (usd per share)					$ 0.000001
Asset acquisition, number of shares converted from each share \| shares					1
Sitio Acquisition, Viper Pubco Merger \| New Viper Class B Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Common stock par value (usd per share)					$ 0.000001
Asset acquisition, number of shares converted from each share \| shares					1
Sitio Acquisition, Viper Pubco Merger \| Former Viper Class A Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Common stock par value (usd per share)					$ 0.000001
Sitio Acquisition, Viper Pubco Merger \| Former Viper Class B Common Stock
Organization, Consolidation and Presentation of Financial Statements [Line Items]
Common stock par value (usd per share)					$ 0.000001

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue


	Year Ended December 31, 2025
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	612	$	519	$	1,131
Natural gas income	31		25		56
Natural gas liquids income	98		61		159
Total royalty income	$	741	$	605	$	1,346


	Year Ended December 31, 2024
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	398	$	352	$	750
Natural gas income	10		5		15
Natural gas liquids income	51		38		89
Total royalty income	$	459	$	395	$	854


	Year Ended December 31, 2023
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In millions)
Oil income	$	377	$	242	$	619
Natural gas income	16		15		31
Natural gas liquids income	42		25		67
Total royalty income	$	435	$	282	$	717

FAIR VALUE MEASUREMENTS - Schedule of Recurring Measurements (Details) - Fair Value, Recurring - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Prepaid expenses and other current assets
Assets:
Total Gross Fair Value	$ 37	$ 24
Gross Amounts Offset in Balance Sheet	(9)	(6)
Net Fair Value Presented in Balance Sheet	28	18
Other current liabilities
Liabilities:
Total Gross Fair Value	9	8
Gross Amounts Offset in Balance Sheet	(9)	(6)
Net Fair Value Presented in Balance Sheet	0	2
Accrued liabilities (2026 WTI Contingent Liability)
Liabilities:
Total Gross Fair Value	20	30
Gross Amounts Offset in Balance Sheet	0	0
Net Fair Value Presented in Balance Sheet	20	30
Other long-term liabilities
Liabilities:
Total Gross Fair Value	7
Gross Amounts Offset in Balance Sheet	0
Net Fair Value Presented in Balance Sheet	7
Level 1 \| Prepaid expenses and other current assets
Assets:
Total Gross Fair Value	0	0
Level 1 \| Other current liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 1 \| Accrued liabilities (2026 WTI Contingent Liability)
Liabilities:
Total Gross Fair Value	0	0
Level 1 \| Other long-term liabilities
Liabilities:
Total Gross Fair Value	0
Level 2 \| Prepaid expenses and other current assets
Assets:
Total Gross Fair Value	37	24
Level 2 \| Other current liabilities
Liabilities:
Total Gross Fair Value	9	8
Level 2 \| Accrued liabilities (2026 WTI Contingent Liability)
Liabilities:
Total Gross Fair Value	20	30
Level 2 \| Other long-term liabilities
Liabilities:
Total Gross Fair Value	7
Level 3 \| Prepaid expenses and other current assets
Assets:
Total Gross Fair Value	0	0
Level 3 \| Other current liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 3 \| Accrued liabilities (2026 WTI Contingent Liability)
Liabilities:
Total Gross Fair Value	0	$ 0
Level 3 \| Other long-term liabilities
Liabilities:
Total Gross Fair Value	$ 0

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
Cybersecurity Risk Management and Strategy Disclosure	Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	Diamondback provides us with personnel and general and administrative services pursuant to the Services and Secondment Agreement, including the personnel and infrastructure that underlie our cybersecurity risk management program. In connection therewith, Diamondback has implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect Diamondback’s systems, identify and remediate on a regular basis vulnerabilities in Diamondback’s systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats. Diamondback has also engaged third-party consultants to conduct penetration testing and risk assessments. Diamondback’s cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration. Diamondback’s cybersecurity risk management program is integrated into its overall enterprise risk management program, which integrates our enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas that apply to us. Diamondback’s cybersecurity risk management program, which it provides to us under the Services and Secondment Agreement, includes: •risk assessments designed to help identify material cybersecurity risks to critical systems, information, products, services, and the broader enterprise IT and operational technology (“OT”) environments; •a security team principally responsible for managing (i) cybersecurity risk assessment processes, (ii) security controls, and (iii) its response to cybersecurity incidents; •the use of external service providers, where appropriate, to assess, test, train or otherwise assist with aspects of its security controls; •security tools deployed in the IT and OT environments for protection against and monitoring for suspicious activity; •cybersecurity awareness training of its employees, including incident response personnel and senior management, including those who provide these services for us; •cybersecurity tabletop exercises for members of its cybersecurity incident response team and legal department; •a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and •a third-party risk management process for service providers, which may include diligence, assessments and/or contractual requirements, depending on each service provider’s operational criticality and relative risk profile.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	Diamondback provides us with personnel and general and administrative services pursuant to the Services and Secondment Agreement, including the personnel and infrastructure that underlie our cybersecurity risk management program. In connection therewith, Diamondback has implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect Diamondback’s systems, identify and remediate on a regular basis vulnerabilities in Diamondback’s systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats. Diamondback has also engaged third-party consultants to conduct penetration testing and risk assessments. Diamondback’s cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration. Diamondback’s cybersecurity risk management program is integrated into its overall enterprise risk management program, which integrates our enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas that apply to us.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	The audit committee of the board of directors receives quarterly updates from Diamondback’s Senior Vice President and Chief Information Officer on the status of Diamondback’s cybersecurity governance program, including as related to new or developing initiatives and any significant security incidents that may occur, to the extent relevant to our program. Board members also receive presentations on cybersecurity topics from Diamondback’s Senior Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	The audit committee of the board of directors receives quarterly updates from Diamondback’s Senior Vice President and Chief Information Officer on the status of Diamondback’s cybersecurity governance program, including as related to new or developing initiatives and any significant security incidents that may occur, to the extent relevant to our program.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	The audit committee of the board of directors receives quarterly updates from Diamondback’s Senior Vice President and Chief Information Officer on the status of Diamondback’s cybersecurity governance program, including as related to new or developing initiatives and any significant security incidents that may occur, to the extent relevant to our program. Board members also receive presentations on cybersecurity topics from Diamondback’s Senior Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies.
Cybersecurity Risk Role of Management [Text Block]	Diamondback’s cybersecurity governance program is led by its Senior Vice President and Chief Information Officer, with support from the internal information technology department. Diamondback’s Senior Vice President and Chief Information Officer has over 20 years of technological leadership experience in the oil and gas industry, providing oversight of all information technology disciplines, including cybersecurity, networking, infrastructure, applications, and data management and protection. Diamondback’s Senior Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), and CompTIASecurity+, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes. In addition, Diamondback’s cybersecurity incident response team is responsible for responding to cybersecurity incidents and is guided by its Computer Security Incident Response Plan. Progress and developments in Diamondback’s cybersecurity governance program are communicated to members of its and our executive team. Diamondback’s and our management takes steps to remain informed about and monitor efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel; threat intelligence and other information obtained from governmental, public or private sources, including third-party consultants engaged by Diamondback; alerts and reports produced by security tools deployed in the enterprise IT and OT environments; and through reporting by employees and service providers. While our board of directors is ultimately responsible for enterprise-wide risk oversight, the board’s committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. In particular, the board’s audit committee is responsible, among other things, for risk management relating to legal and regulatory requirements, including cybersecurity, which plays an integral role in the risk management strategy and continues to be an area of increasing focus for our board, the audit committee and management. The audit committee of the board of directors receives quarterly updates from Diamondback’s Senior Vice President and Chief Information Officer on the status of Diamondback’s cybersecurity governance program, including as related to new or developing initiatives and any significant security incidents that may occur, to the extent relevant to our program. Board members also receive presentations on cybersecurity topics from Diamondback’s Senior Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies. Diamondback’s cybersecurity governance program also includes processes to assess cybersecurity risks related to third-party service providers, suppliers and vendors.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Diamondback’s cybersecurity governance program is led by its Senior Vice President and Chief Information Officer, with support from the internal information technology department.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Diamondback’s Senior Vice President and Chief Information Officer has over 20 years of technological leadership experience in the oil and gas industry, providing oversight of all information technology disciplines, including cybersecurity, networking, infrastructure, applications, and data management and protection. Diamondback’s Senior Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), and CompTIASecurity+, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Progress and developments in Diamondback’s cybersecurity governance program are communicated to members of its and our executive team.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Cash flows from operating activities:
Net income (loss)	$ (206)	$ 604	$ 501
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes	(83)	(149)	(7)
Depletion	607	214	146
Impairment	768	0	0
(Gain) loss on derivative instruments, net	(44)	(11)	26
Net cash receipts (payments) on derivatives	30	(3)	(13)
(Gain) loss on extinguishment of debt	32	0	0
Other	13	6	3
Changes in operating assets and liabilities:
Royalty income receivable	(25)	(13)	(27)
Royalty income receivable—related party	(34)	(28)	3
Accounts payable and accrued liabilities	(19)	7	6
Accounts payable—related party	(2)	1	1
Other	16	(8)	(1)
Net cash provided by (used in) operating activities	1,053	620	638
Cash flows from investing activities:
Proceeds from sale of oil and natural gas interests	0	88	(3)
Net cash provided by (used in) investing activities	(2,424)	(608)	(908)
Cash flows from financing activities:
Proceeds from debt	3,250	842	973
Repayments of debt	(2,163)	(844)	(462)
Net proceeds from public offering	1,232	476	0
Proceeds from public offering to Diamondback	0	0	200
Dividends to stockholders	(328)	(219)	(129)
Dividends to Diamondback	(361)	(255)	(196)
Dividends to other non-controlling interest	(56)	(7)	0
Other	(23)	(4)	(13)
Net cash provided by (used in) financing activities	1,357	(11)	278
Net increase (decrease) in cash and cash equivalents	(14)	1	8
Cash and cash equivalents at beginning of period	27	26	18
Cash and cash equivalents at end of period	13	27	26
Supplemental disclosure of cash flow information:
Interest paid	(70)	(74)	(40)
Cash paid for income taxes, net of refunds:
Federal	(47)	(53)	(50)
State	(2)	(3)	(1)
Supplemental disclosure of non—cash transactions:
Class A Common Stock issued for acquisition	(1,435)	0	(255)
Operating Company Units
Cash flows from financing activities:
Repurchases of shares of Class A Common Stock/OpCo Units as part of the repurchase program	(41)	0	0
Supplemental disclosure of non—cash transactions:
OpCo Units issued	(1,445)	(468)	0
Common Class A
Cash flows from financing activities:
Repurchases of shares of Class A Common Stock/OpCo Units as part of the repurchase program	(153)	0	(95)
Nonrelated Party
Cash flows from investing activities:
Acquisitions of oil and natural gas interests	(1,549)	(696)	(830)
Related Party
Cash flows from investing activities:
Acquisitions of oil and natural gas interests	(875)	0	(75)
Supplemental disclosure of non—cash transactions:
OpCo Units issued	$ (3,599)	$ 0	$ 0

INCOME TAXES - Schedule of Components of Provision for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Current income tax provision (benefit):
Federal	$ 60	$ 47	$ 50
State	4	2	3
Total current income tax provision (benefit)	64	49	53
Deferred income tax provision (benefit):
Federal	(78)	(148)	(7)
State	(5)	(1)	0
Total deferred income tax provision (benefit)	(83)	(149)	(7)
Total provision (benefit) from income taxes	$ (19)	$ (100)	$ 46

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
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-Name Accounting Standards Codification
-Section 55
-Paragraph 4
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Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
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Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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-SubTopic 10
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-Section 50
-Paragraph 1
-Subparagraph (i)
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-URI https://asc.fasb.org/1943274/2147482964/270-10-50-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (ee)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12

Reference 8: http://www.xbrl.org/2003/role/exampleRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 231
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482663/740-10-55-231

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-9

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 6.I.7)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-8

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-10

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(9))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477250/944-220-S99-1

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Subparagraph (a)
-SubTopic 20
-Topic 740
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482659/740-20-45-2

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h))
-SubTopic 10
-Topic 235
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

+ Details

EARNINGS PER COMMON SHARE (Tables)

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Schedule of Basic and Diluted Net Income Per Common Share

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:


	Year Ended December 31,
	2025		2024		2023
	(In millions, except per share amounts, shares in thousands)
Net income (loss) attributable to the period	$	(68)	$	359	$	200
Less: net income (loss) allocated to participating securities(1)	1		—		—
Net income (loss) attributable to common stockholders	$	(69)	$	359	$	200
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	142,530		93,932		74,176
Effect of dilutive securities:
Potential common shares issuable(2)	—		—		—
Diluted weighted average common shares outstanding	142,530		93,932		74,176
Net income (loss) per common share, basic	$	(0.48)	$	3.82	$	2.69
Net income (loss) per common share, diluted	$	(0.48)	$	3.82	$	2.69

INCOME TAXES - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Mar. 31, 2024	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2025	Aug. 19, 2025
Operating Loss Carryforwards [Line Items]
Deferred tax assets, net		$ 185	$ 185		$ 33
Federal capital loss carryforwards					$ 5
Valuation allowance increase (decrease)	$ 11	$ (156)	$ (149)	$ (7)
Deferred income tax assets recognized increase	$ 28
Sitio Acquisition
Operating Loss Carryforwards [Line Items]
Asset acquisition, prepaid income tax						$ 14
Asset acquisition, deferred tax assets related to loss carryforwards						5
Asset acquisition, deferred tax liability						$ 122

Cover - USD ($) $ in Billions	12 Months Ended
Cover - USD ($) $ in Billions	Dec. 31, 2025	Feb. 20, 2026	Jun. 30, 2025
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-42807
Entity Registrant Name	Viper Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	39-2596878
Entity Address, Address Line One	500 West Texas Ave.,
Entity Address, Address Line Two	Suite 100
Entity Address, City or Town	Midland,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	79701
City Area Code	432
Local Phone Number	221-7400
Title of 12(b) Security	Class A Common Stock, $0.000001 Par Value
Trading Symbol	VNOM
Security Exchange Name	NASDAQ
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 Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 5.0
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Portions of Viper Energy, Inc.’s Proxy Statement for the 2026 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
Entity Central Index Key	0002074176
Common Class A
Entity Information [Line Items]
Entity Common Shares Outstanding		176,723,281
Common Class B
Entity Information [Line Items]
Entity Common Shares Outstanding		180,825,588

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities as of the date of the consolidated financial statements. Actual results could differ from those estimates.

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, geopolitical global conflicts, higher interest rates, effects of tariffs, actions taken by OPEC and its non-OPEC allies, known collectively as OPEC+, global supply chain disruptions, measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been and may continue to be impacted materially as a result of these events and changing market conditions. Such circumstances generally increase uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves, including those acquired by the Company, and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests, estimates of third-party operated royalty income related to expected sales volumes and prices, the recoverability of costs of unevaluated properties and estimates of income taxes, including deferred tax valuation allowances. Other areas requiring estimation include commodity derivatives and various fair values of non-oil and gas assets and liabilities.

Revenue from Contracts with Customers

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index.

The Company earns lease bonus income by leasing its mineral interests to exploration, development and production companies. The Company recognizes lease bonus income when a lease agreement has been executed and payment is determined to be collectible.

Royalty Income from Oil, Natural Gas and Natural Gas Liquids Sales

The Company’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the operator of the properties in which the Company owns a royalty interest sells the Company’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Company collects its percentage royalty based on the revenue generated. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

Transaction Price Allocated to Remaining Performance Obligations

The Company’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of the Company’s royalty income contracts.

Contract Balances

Under the Company’s royalty income contracts, it generally has the right to receive its interest in the gross proceeds collected by the operator from third-party purchasers of the Company’s production once production has occurred, at which point payment is unconditional. Accordingly, the Company’s royalty income contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-Period Performance Obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered. As a result, the Company is required to estimate the amount of royalty income to be received based upon the Company’s royalty interest. The Company records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the operator. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition costs from third parties are capitalized and amortized on a composite unit of production method based on proved oil, natural gas and natural gas liquids reserves. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas and natural gas liquids. Acquisitions of mineral and royalty interests from related parties are typically recorded at the parent’s historical carrying value and related transaction costs are expensed as incurred in accordance with guidance in ASC 805 for transactions between entities under common control. At December 31, 2025, and 2024, the Company’s oil and natural gas properties consisted primarily of mineral interests in oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $17.48, $11.77 and $10.20 for the years ended December 31, 2025, 2024 and 2023, respectively. Depletion for oil and natural gas properties was $607 million, $214 million and $146 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized oil and natural gas interests net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, (ii) the cost of properties not being amortized, if any, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. See Note 5—Oil and Natural Gas Interests for additional discussion of the Company’s oil and natural gas properties.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property at least annually for possible impairment. The Company 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: intent of the operator to drill; remaining lease term with the current operator; geological and geophysical evaluations; drilling results and activity; the

assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Royalty Income Receivable

Royalty income receivables consist of receivables for sales of oil, natural gas and natural gas liquids made by the Company’s third-party operators and Diamondback to third-party purchasers. The operators remit payment for production directly to the Company. Most payments for production are received within three months after the production date. Payments on new wells added organically or through acquisition may be further delayed due to title opinion work, which is required to be completed by the operator before payments are released.

Royalty income receivables are stated at amounts due from purchasers, net of an allowance for expected losses as estimated by the Company when collection is deemed doubtful. Royalty income receivables outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance utilizing the loss-rate method, which considers a number of factors, including the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific royalty income receivables when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. At December 31, 2025 and 2024, the Company’s allowance for expected losses was immaterial.

Concentrations

The Company is subject to risk resulting from the concentration of its royalty income in producing oil and natural gas properties and receivables with several significant operators. For the year ended December 31, 2025, two operators each accounted for more than 10% of royalty income: Diamondback (55%) and ExxonMobil Corporation (14%). For the year ended December 31, 2024, two operators each accounted for more than 10% of royalty income: Diamondback (54%) and Pioneer Natural Resources (11%). For the year ended December 31, 2023, one operator accounted for more than 10% of royalty income: Diamondback (61%). Each of the Company’s operators sell to multiple purchasers. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact the Company’s operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Related Party Transactions

Royalty Income Receivable

As of December 31, 2025 and 2024, Diamondback, either directly or through its consolidated subsidiaries, owed the Company $88 million and $31 million, respectively, for royalty income received from third parties for the Company’s production, which had not yet been remitted to the Company.

Lease Bonus Income

During the year ended December 31, 2025, Diamondback and its subsidiaries paid the Operating Company $24 million of lease bonus income for 18 new leases covering 2,356 acres in Dawson, Glasscock, Howard, Martin, Midland and Reagan Counties, Texas. Lease bonus income from Diamondback for the year ended December 31, 2024 was immaterial. During the year ended December 31, 2023, Diamondback and its subsidiaries paid the Operating Company $108 million of lease bonus income, which included (i) one new lease of $96 million covering certain acreage in our Spanish Trail prospect in Midland County, Texas, from a lease agreement with a subsidiary of Diamondback on terms substantially identical to the Operating Company’s other lease arrangements with Diamondback and was considered and approved by the conflicts committee of the board of directors, (ii) nine other new leases covering 703 acres in Martin, Midland, Pecos, and Wheeler Counties, Texas, and (iii) two lease extensions covering 25 acres in Martin County, Texas.

Other Related Party Transactions

See Note 4—Acquisitions and Divestitures for significant related party acquisitions of oil and natural gas interests.

See Note 7—Stockholders’ Equity for further details regarding equity transactions with related parties.

All other related party transactions with Diamondback or its affiliates have been stated on the face of the consolidated financial statements or were insignificant for the years ended December 31, 2025, 2024 and 2023, respectively.

Derivative Instruments

The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

Income Taxes

The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities, and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2025, 2024 and 2023, there were no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements. See Note 9—Income Taxes for further details.

Non-Controlling Interest

Non-controlling interest in the accompanying consolidated financial statements represents the ownership interests of Diamondback, former equity holders of Sitio Royalties Operating Partnership, LP (“Sitio OpCo”), Tumbleweed Royalty IV, LLC (“TWR IV”) and the Morita Ranches Equity Recipients (as defined and discussed in Note 4—Acquisitions and Divestitures) in the net assets of the Operating Company. When the non-controlling interests’ relative ownership in the Operating Company changes, adjustments to non-controlling interest and stockholders’ equity, tax effected, will occur. Because these changes in the Company’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 Company’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 7—Stockholders’ Equity for further discussion of changes in ownership interest.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The- Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consist of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
Derivative instruments	$	28	$	18
Prepaid expenses	13		11
Other	9		2
Total prepaid expenses and other current assets	$	50	$	31

See “—Derivative Instruments” above for the Company’s accounting policy for derivative instruments.

Accrued Liabilities

The Company’s accrued liabilities are financial instruments for which the carrying value approximates fair value.

Accrued liabilities consist of the following as of the dates indicated:


	December 31,
	2025		2024
	(In millions)
Interest payable	$	39	$	10
Ad valorem taxes payable	34		20

Acquisition adjustment accrual	4		9
2026 WTI Contingent Liability	20		—
Other	10		4
Total accrued liabilities	$	107	$	43

Debt Issuance Costs

Other assets include capitalized costs related to our current credit facility, the previous credit facility and the Term Loan (as defined and discussed in Note 6—Debt) of $21 million and $18 million, and accumulated amortization of those costs over the term of the respective credit facilities of $13 million and $11 million as of December 31, 2025 and 2024, respectively.

Long-term debt includes capitalized costs related to the Guaranteed Senior Notes. The costs associated with the Guaranteed Senior Notes are netted against the Guaranteed Senior Notes’ balances and amortized over the term of the Guaranteed Senior Notes using the effective interest method. See Note 6—Debt for further details.

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated, and provides additional requirements regarding income taxes paid. The Company adopted the amendments in 2025 and applied the guidance on a retrospective basis. Adoption of the update resulted in additional disclosures in Note 9—Income Taxe s but did not impact the Company’s financial position, results of operations or liquidity.

In September 2025, the FASB issued ASU 2025-07, “Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606) – Derivatives Scope Refinements and Scope Clarification for Share-Based Noncash Consideration from a Customer in a Revenue Contract.” The ASU addresses (i) the application of derivative accounting to

contracts that include features based on the operations or activities of one of the parties to the contract and (ii) diversity in practice related to accounting for share-based noncash consideration from a customer. The Company elected to early-adopt this amendment in 2025 and applied the guidance on a prospective basis. Adoption of the update did not impact the Company’s historical financial position, results of operations or liquidity; however, the guidance may affect whether certain new arrangements qualify for derivative accounting.

Accounting Pronouncements Not Yet Adopted

In November 2024, the FASB issued ASU 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses,” which requires additional disclosure about specified categories of expenses included in relevant expense captions presented on the income statement. The amendments are effective for annual periods beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.

The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

STOCKHOLDERS’ EQUITY - Schedule of Beneficial Ownership of Common Stock and OpCo Units (Details)	Dec. 31, 2025 shares
Common Class \| Viper Energy Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	368,060,055
Percentage Ownership	100.00%
Operating Company Units \| VNOM Holding Company LLC
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	368,060,055
Percentage Ownership	100.00%
Public equity holders of Class A Common Stock \| Common Class \| Viper Energy Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	170,942,687
Percentage Ownership	46.50%
Public equity holders of Class A Common Stock \| Operating Company Units \| VNOM Holding Company LLC
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	0
Percentage Ownership	0.00%
Viper and subsidiaries \| Common Class \| Viper Energy Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	0
Percentage Ownership	0.00%
Viper and subsidiaries \| Operating Company Units \| VNOM Holding Company LLC
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	170,942,687
Percentage Ownership	46.50%
Diamondback and subsidiaries \| Common Class \| Viper Energy Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	155,058,093
Percentage Ownership	42.10%
Diamondback and subsidiaries \| Operating Company Units \| VNOM Holding Company LLC
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	155,058,093
Percentage Ownership	42.10%
Sitio OpCo former equity holders \| Common Class \| Viper Energy Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	29,565,308
Percentage Ownership	8.00%
Sitio OpCo former equity holders \| Operating Company Units \| VNOM Holding Company LLC
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	29,565,308
Percentage Ownership	8.00%
TWR IV \| Common Class \| Viper Energy Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	10,093,670
Percentage Ownership	2.70%
TWR IV \| Operating Company Units \| VNOM Holding Company LLC
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	10,093,670
Percentage Ownership	2.70%
Morita Ranches Equity Recipients \| Common Class \| Viper Energy Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	2,400,297
Percentage Ownership	0.70%
Morita Ranches Equity Recipients \| Operating Company Units \| VNOM Holding Company LLC
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares of Common Stock Beneficially Owned (in shares)	2,400,297
Percentage Ownership	0.70%