0001602065-25-000010 | 10-K | XBRL Viewer

OIL AND NATURAL GAS INTERESTS

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


	December 31,
	2024		2023
	(In thousands)
Oil and natural gas interests:
Subject to depletion	$	3,532,834	$	2,859,642
Not subject to depletion	2,179,837		1,769,341
Gross oil and natural gas interests	5,712,671		4,628,983
Accumulated depletion and impairment	(1,080,764)		(866,352)
Oil and natural gas interests, net	4,631,907		3,762,631
Land	5,688		5,688
Property, net of accumulated depletion and impairment	$	4,637,595	$	3,768,319

Balance of costs not subject to depletion:
Incurred in 2024	$	798,705
Incurred in 2023	576,162
Incurred in 2022	33,053
Prior	771,917
Total not subject to depletion	$	2,179,837

As of December 31, 2024 and 2023, the Company had mineral and royalty interests representing approximately 35,671 and 34,217 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 eight to ten years.

Based on the results of the quarterly ceiling tests, the Company was not required to record an impairment on the Company’s proved oil and natural gas interests for the years ended December 31, 2024, 2023 and 2022. In addition to commodity prices, the Company’s production rates, levels of proved reserves, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If the trailing 12-month commodity prices were to fall as compared to the commodity prices used in prior quarters, the Company could have write-downs in subsequent quarters, which may be material.

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents	$ 26,851	$ 25,869
Income tax receivable	2,238	813
Derivative instruments	17,638	358
Prepaid expenses and other current assets	11,112	4,467
Total current assets	238,044	143,517
Property:
Oil and natural gas interests, full cost method of accounting ($2,179,837 and $1,769,341 excluded from depletion at December 31, 2024 and December 31, 2023, respectively)	5,712,671	4,628,983
Land	5,688	5,688
Accumulated depletion and impairment	(1,080,764)	(866,352)
Property, net	4,637,595	3,768,319
Derivative instruments	0	92
Deferred income taxes (net of allowances)	185,235	56,656
Other assets	8,166	5,509
Total assets	5,069,040	3,974,093
Current liabilities:
Accrued liabilities	42,272	27,021
Derivative instruments	2,323	2,961
Income taxes payable	2,034	1,925
Total current liabilities	48,694	33,256
Long-term debt, net	1,082,979	1,083,082
Derivative instruments	0	201
Other long-term liabilities	30,148	0
Total liabilities	1,161,821	1,116,539
Commitments and Contingencies
Stockholders’ equity:
Additional paid-in capital	1,568,560	1,031,078
Retained earnings (accumulated deficit)	118,444	(16,786)
Total Viper Energy, Inc. stockholders’ equity	1,687,004	1,014,292
Non-controlling interest	2,220,215	1,843,262
Total equity	3,907,219	2,857,554
Total liabilities and stockholders’ equity	5,069,040	3,974,093
Common Class A
Stockholders’ equity:
Common Stock	$ 0	$ 0
Common stock outstanding (in shares)	102,977,142	86,144,273
Common stock issued (in shares)	102,977,142	86,144,273
Common Class B
Stockholders’ equity:
Common Stock	$ 0	$ 0
Common stock outstanding (in shares)	85,431,453	90,709,946
Common stock issued (in shares)	85,431,453	90,709,946
Nonrelated Party
Current assets:
Royalty income receivable	$ 149,234	$ 108,681
Current liabilities:
Accounts payable	85	19
Related Party
Current assets:
Royalty income receivable	30,971	3,329
Current liabilities:
Accounts payable	$ 1,980	$ 1,330

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash flows from operating activities:
Net income (loss)	$ 603,646	$ 501,341	$ 655,004
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes	(149,085)	(7,000)	(49,656)
Depletion	214,412	146,118	121,071
(Gain) loss on derivative instruments, net	(11,386)	25,793	18,138
Net cash receipts (payments) on derivatives	(2,978)	(13,319)	(31,319)
Other	6,197	3,442	5,070
Changes in operating assets and liabilities:
Royalty income receivable	(13,249)	(27,379)	(13,089)
Royalty income receivable—related party	(27,642)	2,931	(4,116)
Accounts payable and accrued liabilities	7,002	6,311	151
Accounts payable—related party	651	1,024	306
Income taxes payable	109	1,014	440
Other	(8,069)	(2,084)	(2,204)
Net cash provided by (used in) operating activities	619,608	638,192	699,796
Cash flows from investing activities:
Proceeds from sale of oil and natural gas interests	87,669	(3,164)	111,702
Net cash provided by (used in) investing activities	(608,573)	(908,365)	47,571
Cash flows from financing activities:
Proceeds from borrowings under credit facility	842,000	573,000	272,000
Repayment on credit facility	(844,000)	(462,000)	(424,000)
Proceeds from Notes	0	400,000	0
Repayment of Notes	0	0	(48,963)
Net proceeds from public offering	475,906	0	0
Proceeds from public offering to Diamondback	0	200,000	0
Repurchased shares/units under buyback program	0	(95,221)	(150,593)
Dividends/distributions to stockholders	(219,465)	(128,777)	(182,835)
Dividends/distributions to Diamondback	(254,216)	(195,976)	(234,103)
Dividends to other non-controlling interest	(7,368)	0	0
Other	(2,910)	(13,163)	(142)
Net cash provided by (used in) financing activities	(10,053)	277,863	(768,636)
Net increase (decrease) in cash and cash equivalents	982	7,690	(21,269)
Cash, cash equivalents and restricted cash at beginning of period	25,869	18,179	39,448
Cash, cash equivalents and restricted cash at end of period	26,851	25,869	18,179
Supplemental disclosure of cash flow information:
Interest paid	(73,860)	(40,187)	(36,868)
Cash (paid) received for income taxes	(56,125)	(51,345)	(16,990)
Supplemental disclosure of non—cash transactions:
Class A Common Stock issued for acquisition	0	254,600	0
Operating Company Units
Supplemental disclosure of non—cash transactions:
OpCo Units issued for acquisition	468,346	0	0
Related Party
Cash flows from investing activities:
Acquisitions of oil and natural gas interests	0	(75,073)	0
Nonrelated Party
Cash flows from investing activities:
Acquisitions of oil and natural gas interests	$ (696,242)	$ (830,128)	$ (64,131)

DEBT (Tables)

12 Months Ended

Dec. 31, 2024

Debt Disclosure [Abstract]

Schedule of Maturities of Long-Term Debt

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


	December 31,
	2024		2023
	(In thousands)
5.375% Senior Notes due 2027	$	430,350	$	430,350
7.375% Senior Notes due 2031	400,000		400,000
Revolving credit facility	261,000		263,000
Unamortized debt issuance costs	(5,836)		(6,903)
Unamortized discount	(2,535)		(3,365)
Total long-term debt	$	1,082,979	$	1,083,082

Schedule of Financial Covenants

The credit facility contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, excess cash and entering into certain swap agreements and require the maintenance of the financial ratios described below.


Financial Covenant						Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit facility						Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit facility						Not less than 1.0 to 1.0
Ratio of secured debt to EBITDAX, as defined in the credit facility						Not greater than 2.5 to 1.0

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, 2024, 2023 and 2022:


	Year Ended December 31,
	2024		2023		2022
	(In thousands)
Interest expense	$	74,373	$	48,222	$	37,539
Other fees and expenses	1,529		836		2,883
Less: interest income	2,054		1,666		428


Interest expense, net	$	73,848	$	47,392	$	39,994

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 Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
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	$ 3,186,886	$ 3,454,096	$ 2,093,117
Purchase of minerals in place	354,874	473,742	30,331
Divestiture of reserves	(51,119)	0	(30,076)
Sales of oil and natural gas, net of production costs	(792,694)	(666,709)	(781,604)
Extensions and discoveries	640,438	626,854	844,010
Net changes in prices and production costs	(438,456)	(1,405,205)	1,131,202
Revisions of previous quantity estimates	(84,949)	2,726	309,338
Net changes in income taxes	70,333	212,391	(393,652)
Accretion of discount	373,790	427,998	234,717
Net changes in timing of production and other	60,441	60,993	16,713
Standardized measure of discounted future net cash flows at the end of the period	$ 3,319,544	$ 3,186,886	$ 3,454,096

COMMITMENTS AND CONTINGENCIES	12 Months Ended
COMMITMENTS AND CONTINGENCIES	Dec. 31, 2024
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.

INCOME TAXES - Schedule of Components of Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current income tax provision (benefit):
Federal	$ 47,264	$ 50,414	$ 15,929
State	2,110	2,538	1,074
Total current income tax provision (benefit)	49,374	52,952	17,003
Deferred income tax provision (benefit):
Federal	(148,439)	(6,532)	(49,656)
State	(646)	(468)	0
Total deferred income tax provision (benefit)	(149,085)	(7,000)	(49,656)
Total provision (benefit) from income taxes	$ (99,711)	$ 45,952	$ (32,653)
Effective tax rates	(19.80%)	8.40%	(5.20%)

OIL AND NATURAL GAS INTERESTS (Tables)

12 Months Ended

Dec. 31, 2024

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,
	2024		2023
	(In thousands)
Oil and natural gas interests:
Subject to depletion	$	3,532,834	$	2,859,642
Not subject to depletion	2,179,837		1,769,341
Gross oil and natural gas interests	5,712,671		4,628,983
Accumulated depletion and impairment	(1,080,764)		(866,352)
Oil and natural gas interests, net	4,631,907		3,762,631
Land	5,688		5,688
Property, net of accumulated depletion and impairment	$	4,637,595	$	3,768,319

Balance of costs not subject to depletion:
Incurred in 2024	$	798,705
Incurred in 2023	576,162
Incurred in 2022	33,053
Prior	771,917
Total not subject to depletion	$	2,179,837

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


	December 31,
	2024		2023
	(In thousands)
Oil and natural gas interests:
Proved	$	3,532,834	$	2,859,642
Unproved	2,179,837		1,769,341
Total oil and natural gas interests	5,712,671		4,628,983
Accumulated depletion and impairment	(1,080,764)		(866,352)
Net oil and natural gas interests capitalized	$	4,631,907	$	3,762,631

OIL AND NATURAL GAS INTERESTS - Additional Information (Details)	12 Months Ended
	Dec. 31, 2024 USD ($) a	Dec. 31, 2023 USD ($) a	Dec. 31, 2022 USD ($)
Oil and Gas, Acreage [Line Items]
Net royalty acres \| a	35,671	34,217
Impairment \| $	$ 0	$ 0	$ 0
Commodity prices, trailing period	12 months
Minimum
Oil and Gas, Acreage [Line Items]
Anticipated timing of cost inclusion in amortization calculation	8 years
Maximum
Oil and Gas, Acreage [Line Items]
Anticipated timing of cost inclusion in amortization calculation	10 years

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, 2024 MBoe well reserve MBbls MMcf	Dec. 31, 2023 MBoe well MBbls MMcf	Dec. 31, 2022 MBoe well MBbls MMcf
Reserve Quantities [Line Items]
Extensions and discoveries (in MBOE)	24,936	25,558	25,858
Oil and gas, development well drilled, net productive, number (in wells) \| well	1,170	904	636
New proved undeveloped location (in wells) \| well	447	179	199
Positive (downward) revisions of previous estimates (in MBOE)	(2,894)	138	8,477
Revisions of previous estimated quantities, due to lower commodity prices (in MBOE)	6,539
Proved undeveloped reserves downgrades	2,936	5,548	7,007
Positive revisions of previous estimated quantities due to performance revision (in MBOE)	6,580	5,688	15,484
Purchase of reserves in place (in MBOE)	14,941	18,977	1,006
Divestitures (in MBOE)	2,138		2,047
Proved undeveloped reserves (in MBOE)	32,009	35,878	41,609
Number of horizontal wells developed \| well	837
Undeveloped reserves transferred to developed (in MBOE)	16,696
Proved undeveloped reserves, revisions (in MBOE)	(1,934)
Proved undeveloped reserves, downgrades (in MBOE)	2,642
Proved undeveloped reserves, positive additions (in MBOE)	9,848
Proved undeveloped reserves, purchases (in MBOE)	4,913
Planned development period	5 years
Reserves were classified as proved developed non-producing \| reserve	0
Oil
Reserve Quantities [Line Items]
Proved undeveloped reserve (volume) \| MBbls	17,543	20,860	24,187
Natural Gas
Reserve Quantities [Line Items]
Proved undeveloped reserve (volume) \| MMcf	39,353	42,116	48,845
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved undeveloped reserve (volume) \| MBbls	7,907	7,999	9,281
Middle Spraberry/Jo Mill
Reserve Quantities [Line Items]
Number of horizontal wells developed \| well	219
Wolfcamp A
Reserve Quantities [Line Items]
Number of horizontal wells developed \| well	212
Lower Spraberry
Reserve Quantities [Line Items]
Number of horizontal wells developed \| well	195
Wolfcamp B
Reserve Quantities [Line Items]
Number of horizontal wells developed \| well	144
Bone Spring
Reserve Quantities [Line Items]
Number of horizontal wells developed \| well	44
Dean
Reserve Quantities [Line Items]
Number of horizontal wells developed \| well	16
Wolfcamp D
Reserve Quantities [Line Items]
Number of horizontal wells developed \| well	7

DERIVATIVES - Schedule of Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Gain (loss) on derivative instruments	$ 11,386	$ (25,793)	$ (18,138)
Net cash receipts (payments) on derivatives	(2,978)	$ (13,319)	(31,319)
Cash paid on commodity contracts terminated prior to their contractual maturity			$ 6,600
2026 WTI Contingent Liability
Derivative [Line Items]
Unrealized loss on derivatives	$ 3,600

The net change in the difference between the fair value and the carrying value, or in the comparative fair values, of derivative instruments, including options, swaps, futures, and forward contracts, held at each balance sheet date, that was included in earnings for the period.

STOCKHOLDERS’ EQUITY - Schedule of Cash Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
Diamondback Energy, Inc.
Class of Stock [Line Items]
Limited partners' capital account, units outstanding (in shares)				731,500
Cash Distribution
Class of Stock [Line Items]
Amount per Operating Company Unit/Amount per Common Share (usd per share)	$ 0.61	$ 0.64	$ 0.59	$ 0.56	$ 0.57	$ 0.36	$ 0.33	$ 0.49	$ 0.49	$ 0.81	$ 0.67	$ 0.47
Cash Distribution \| Operating Company Share
Class of Stock [Line Items]
Amount per Operating Company Unit/Amount per Common Share (usd per share)	$ 0.73	$ 0.76	$ 0.70	$ 0.69	$ 0.70	$ 0.44	$ 0.42	$ 0.54	$ 0.52	$ 0.87	$ 0.70	$ 0.47
Operating Company Distributions to Diamondback/Common Unitholders	$ 62,366	$ 64,927	$ 59,803	$ 62,590	$ 63,497	$ 39,912	$ 38,097	$ 48,983	$ 47,170	$ 78,918	$ 63,497	$ 42,634
Cash Distribution \| Common Stock
Class of Stock [Line Items]
Operating Company Distributions to Diamondback/Common Unitholders	$ 62,932	$ 58,669	$ 54,077	$ 48,337	$ 49,126	$ 25,563	$ 23,797	$ 35,683	$ 36,076	$ 60,626	$ 51,680	$ 36,238

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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Revenue from Contract with Customer [Abstract]

INCOME TAXES - Additional Information (Details) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 13, 2023	Mar. 31, 2024	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Loss Carryforwards [Line Items]
Deferred tax assets, net			$ 184,849	$ 184,849	$ 56,656
Valuation allowance increase (decrease)		$ 10,800	$ (155,900)	(149,100)	(7,000)	$ (49,700)
Shares converted (in shares)	1
Deferred income tax assets recognized increase		$ 28,200
State income tax expense				$ 2,110	$ 2,538	$ 1,074
Common Class B
Operating Loss Carryforwards [Line Items]
Shares converted (in shares)		5,280,000
Operating Company Units
Operating Loss Carryforwards [Line Items]
Shares converted (in shares)	1	5,280,000

REVENUE FROM CONTRACTS WITH CUSTOMERS

12 Months Ended

Dec. 31, 2024

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, 2024, 2023 and 2022, 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, 2024
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In thousands)
Oil income	$	398,010	$	352,233	$	750,243
Natural gas income	9,734		5,079		14,813
Natural gas liquids income	50,784		37,736		88,520
Total royalty income	$	458,528	$	395,048	$	853,576


	Year Ended December 31, 2023
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In thousands)
Oil income	$	376,961	$	242,220	$	619,181
Natural gas income	16,040		14,913		30,953
Natural gas liquids income	42,131		24,845		66,976
Total royalty income	$	435,132	$	281,978	$	717,110


	Year Ended December 31, 2022
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In thousands)
Oil income	$	397,282	$	269,999	$	667,281
Natural gas income	44,232		38,917		83,149
Natural gas liquids income	56,382		31,164		87,546
Total royalty income	$	497,896	$	340,080	$	837,976

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.

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Beginning balance (in shares) at Dec. 31, 2021

FAIR VALUE MEASUREMENTS - Schedule of Recurring Measurements (Details) - Fair Value, Recurring - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Derivative instruments \| Current Assets
Assets:
Total Gross Fair Value	$ 23,816	$ 7,040
Gross Amounts Offset in Balance Sheet	(6,178)	(6,682)
Net Fair Value Presented in Balance Sheet	17,638	358
Derivative instruments \| Noncurrent Assets
Assets:
Total Gross Fair Value		1,269
Gross Amounts Offset in Balance Sheet		(1,177)
Net Fair Value Presented in Balance Sheet		92
Derivative instruments \| Current Liabilities
Liabilities:
Total Gross Fair Value	8,501	9,643
Gross Amounts Offset in Balance Sheet	(6,178)	(6,682)
Net Fair Value Presented in Balance Sheet	2,323	2,961
Derivative instruments \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value		1,378
Gross Amounts Offset in Balance Sheet		(1,177)
Net Fair Value Presented in Balance Sheet		201
2026 WTI Contingent Liability \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	29,762
Gross Amounts Offset in Balance Sheet	0
Net Fair Value Presented in Balance Sheet	29,762
Level 1 \| Derivative instruments \| Current Assets
Assets:
Total Gross Fair Value	0	0
Level 1 \| Derivative instruments \| Noncurrent Assets
Assets:
Total Gross Fair Value		0
Level 1 \| Derivative instruments \| Current Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 1 \| Derivative instruments \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value		0
Level 1 \| 2026 WTI Contingent Liability \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	0
Level 2 \| Derivative instruments \| Current Assets
Assets:
Total Gross Fair Value	23,816	7,040
Level 2 \| Derivative instruments \| Noncurrent Assets
Assets:
Total Gross Fair Value		1,269
Level 2 \| Derivative instruments \| Current Liabilities
Liabilities:
Total Gross Fair Value	8,501	9,643
Level 2 \| Derivative instruments \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value		1,378
Level 2 \| 2026 WTI Contingent Liability \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	29,762
Level 3 \| Derivative instruments \| Current Assets
Assets:
Total Gross Fair Value	0	0
Level 3 \| Derivative instruments \| Noncurrent Assets
Assets:
Total Gross Fair Value		0
Level 3 \| Derivative instruments \| Current Liabilities
Liabilities:
Total Gross Fair Value	0	0
Level 3 \| Derivative instruments \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value		$ 0
Level 3 \| 2026 WTI Contingent Liability \| Noncurrent Liabilities
Liabilities:
Total Gross Fair Value	$ 0

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2024
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS 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) $211.0 million in cash and (ii) 2.40 million 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”), subject to certain 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 OpCo, 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 our 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 with the Morita Ranches Equity Recipients, 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 8.6% and current production of approximately 768 BO/d. The Company funded the cash consideration for the Morita Ranches Acquisition with cash on hand. 2025 Equity Offering On February 3, 2025, the Company completed an underwritten public offering of approximately 28.34 million shares of Class A Common Stock, which included approximately 3.70 million 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 intends to use the net proceeds from the 2025 Equity Offering to fund the cash consideration for Pending 2025 Drop Down (defined below), if it closes, and the remaining net proceeds will be used for general corporate purposes. If the Pending 2025 Drop Down does not close, the Company will use the net proceeds from the 2025 Equity Offering for general corporate purposes. Pending 2025 Drop Down Transaction On January 30, 2025, the Company and the Operating Company, as buyer parties, entered into a definitive equity purchase agreement with Endeavor Energy Resources, LP (“Endeavor”) and 1979 Royalties, LP and 1979 Royalties GP, LLC (collectively, the “Endeavor Subsidiaries”), each of which is a subsidiary of Diamondback, to acquire the Endeavor Subsidiaries from Endeavor for consideration consisting of (i) $1.0 billion in cash and (ii) the issuance of 69.63 million OpCo Units and an equivalent number of shares of the Company’s Class B Common Stock (collectively, the “Equity Issuance”), in each case subject to customary closing adjustments, including, among other things, for net title benefits (such transaction, the “Pending 2025 Drop Down”). The OpCo Units and the Class B Common Stock to be issued in the Pending 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 our 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 to be issued at the closing of the Pending 2025 Drop Down, are subject to our existing registration rights agreement with Diamondback, dated as of November 13, 2023, previously filed by us with the SEC. The mineral and royalty interests owned by the Endeavor Subsidiaries and to be acquired in the Pending 2025 Drop Down represent approximately 22,847 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback, and have an average net royalty interest of approximately 2.8% and 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 6,055 gross proved developed production wells (of which approximately 29% 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 audit committee of the Company’s board of directors, comprised of all independent directors and advised by its legal counsel and financial advisor, negotiated and approved the Pending 2025 Drop Down and the transactions contemplated thereby, and recommended that the board of directors approve the Pending 2025 Drop Down and the transactions contemplated thereby, in each case, subject to the Company’s receipt of the requisite stockholder and regulatory approvals and the satisfaction or waiver of other closing conditions discussed below. Based on that recommendation, and subject to the same approvals and conditions, the board of directors also approved the Pending 2025 Drop Down on January 30, 2025. The completion of the Pending 2025 Drop Down is subject to (i) the approval of the Pending 2025 Drop Down by (a) the holders of a majority of the voting power of the Company’s Common Stock entitled to vote on such proposal, voting together as a single class, at the special meeting of our stockholders, excluding the shares beneficially owned by Diamondback and its subsidiaries, and (b) the holders of a majority of the Company’s outstanding Common Stock, in each case, as required by Delaware law, (ii) regulatory clearance under the Hart-Scott-Rodino Antitrust Improvement Act and (iii) the satisfaction or waiver of other customary closing conditions. In addition, the Equity Issuance is subject to the approval by the Company’s stockholders representing a majority of the total votes cast at the special meeting on such proposal, as required by the rules of Nasdaq Stock Market LLC. The Company expects to hold the special meeting of its stockholders and, subject to the satisfaction or waiver of the foregoing conditions, close the Pending 2025 Drop Down during the second quarter of 2025. After giving effect to the 2025 Equity Offering and the Morita Ranches Acquisition, the Company currently estimates that following the closing of the Pending 2025 Drop Down, Diamondback will beneficially own approximately 52% of the Company’s outstanding Common Stock, on a fully diluted basis. The Company intends to fund the cash consideration for the Pending 2025 Drop Down with the proceeds from the 2025 Equity Offering. The Pending 2025 Drop Down will be accounted for as a transaction between entities under common control with the acquired properties recorded at Endeavor’s historical carrying value in the Company’s consolidated balance sheet. Cash Dividend On January 30, 2025, the board of directors of the Company approved a cash dividend for the fourth quarter of 2024 of $0.65 per share of Class A Common Stock and $0.69 per OpCo Unit, in each case, payable on March 13, 2025, to holders of record at the close of business on March 6, 2025. The dividend on Class A Common Stock consists of a base quarterly dividend of $0.30 per share and a variable quarterly dividend of $0.35 per share.

Consolidated Statement of Stockholders’ Equity - USD ($)
$ in Thousands

Total

New Issues Of Common Stock

Common Class A

Common Class B

Operating Company Units

General Partner

Non-Controlling Interest

Common Units [Member]

Limited Partners

Class B Units

Limited Partners

Common Stock

Common Class A

Common Stock

Common Class A

New Issues Of Common Stock

Common Stock

Common Class A

New Issues From Vesting Of Equity Awards

Common Stock

Common Class B

Additional Paid-in Capital

New Issues Of Common Stock

Retained Earnings (Accumulated Deficit)

Non-Controlling Interest

Operating Company Units

78,546,000

90,710,000

Beginning balance at Dec. 31, 2021

$ 2,232,828

$ 729

$ 1,418,007

$ 813,161

$ 931

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

Unit-based compensation

1,304

$ 1,304

Vesting of restricted stock units (in shares)

79,000

Distribution equivalent rights payments

(365)

$ (365)

Distributions to public

(182,470)

Distributions to Diamondback

(234,103)

(232,219)

(1,785)

$ (99)

Distributions to General Partner

(80)

Change in ownership of consolidated subsidiaries, net

(58,253)

$ 58,253

Repurchased units as part of share/unit buyback (in shares)

(1,500,000)

(5,395,000)

(150,593)

$ (37,300)

$ (150,593)

151,673

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

655,004

503,331

$ 151,673

73,230,000

90,710,000

Ending balance at Dec. 31, 2022

649

$ 689,178

$ 832

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

Stock issued during period, shares, new issues (in shares)

79,000

Change in ownership of consolidated subsidiaries, net

(58,253)

$ 58,253

(150,593)

$ (37,300)

(150,593)

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

655,004

$ 503,331

$ 151,673

^[1]

Ending balance at Dec. 31, 2022

2,321,525

$ 0

$ 1,630,866

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

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

(78,126,000)

(90,710,000)

Conversion of Viper Energy Partnership Units to Viper Energy Inc. Common Shares

$ (937,468)

$ (757)

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

7,215,000

Common shares/units issued to related party

200,000

$ 200,000

Vesting of restricted stock units (in shares)

1,302

$ 1,098

204

73,000

Distribution equivalent rights payments

(211)

$ (163)

(48)

Distributions to public

(128,566)

(84,018)

(44,548)

Distributions to Diamondback

(195,976)

(862)

$ (75)

(20)

(4,530)

(190,489)

Distributions to General Partner

(90)

Change in ownership of consolidated subsidiaries, net

$ 31,668

(133,300)

101,632

Repurchased units as part of share/unit buyback (in shares)

(2,392,000)

(1,000,000)

^[1]

(95,221)

$ (67,181)

(28,040)

200,088

32,340

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

501,341

$ 167,748

301,253

Ending balance at Dec. 31, 2023

$ 0

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

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

^[1]

78,126,000

90,710,000

Conversion of Viper Energy Partnership Units to Viper Energy Inc. Common Shares

938,225

Liquidation of General Partner

(1,150)

$ (559)

(591)

Common shares/units issued for acquisition (in shares)

^[1]

9,018,000

Common shares/units issued for acquisition

254,600

Stock issued during period, shares, new issues (in shares)

73,000

Change in ownership of consolidated subsidiaries, net

1,302

$ 1,098

204

31,668

(133,300)

101,632

(95,221)

(67,181)

(28,040)

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

501,341

$ 167,748

301,253

86,144,273

90,709,946

86,144,000

^[1],[2]

90,710,000

^[1],[2]

Ending balance at Dec. 31, 2023

2,857,554

1,031,078

(16,786)

1,843,262

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

Vesting of restricted stock units (in shares)

2,975

^[2]

11,500,000

54,000

Change in ownership of consolidated subsidiaries, net

(20,027)

58,713

(78,740)

359,245

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

603,646

359,245

244,401

Common shares/units issued for acquisition

$ 468,346

Common stock converted in diamondback offering (in shares)

^[2]

5,279,000

Stock issued during period, shares, new issues (in shares)

^[2]

11,500,000

54,000

Stock issued during period, value, new issues

$ 475,906

Cash paid for tax withholding on vested equity awards

2,975

(132)

Distribution equivalent rights payments

(393)

Dividends to stockholders

(219,072)

Dividends to Diamondback

(254,216)

(4,550)

(249,686)

Dividends to other non-controlling interest

(7,368)

Change in ownership of consolidated subsidiaries, net

(20,027)

58,713

(78,740)

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

603,646

359,245

244,401

102,977,142

85,431,453

102,977,000

^[2]

85,431,000

^[2]

Ending balance at Dec. 31, 2024

$ 3,907,219

$ 1,568,560

$ 118,444

$ 2,220,215

[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.

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2024
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

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating income:
Royalty income	$ 853,576	$ 717,110	$ 837,976
Other operating income	640	909	700
Total operating income	860,387	827,697	866,467
Costs and expenses:
Production and ad valorem taxes	60,882	50,401	56,372
Depletion	214,412	146,118	121,071
Other operating (income) expense	55	356	0
Total costs and expenses	293,990	207,478	185,985
Income (loss) from operations	566,397	620,219	680,482
Other income (expense):
Interest expense, net	(73,848)	(47,392)	(39,994)
Gain (loss) on derivative instruments, net	11,386	(25,793)	(18,138)
Other income, net	0	259	1
Total other expense, net	(62,462)	(72,926)	(58,131)
Income (loss) before income taxes	503,935	547,293	622,351
Provision for (benefit from) income taxes	(99,711)	45,952	(32,653)
Net income (loss)	603,646	501,341	655,004
Net income (loss) attributable to non-controlling interest	244,401	301,253	503,331
Net income (loss) attributable to Viper Energy, Inc.	$ 359,245	$ 200,088	$ 151,673
Net income (loss) attributable to common shares:
Basic (dollars per shares)	$ 3.82	$ 2.69	$ 2.00
Diluted (dollars per shares)	$ 3.82	$ 2.69	$ 2.00
Weighted average number of common shares outstanding:
Basic (in shares)	93,932	74,176	75,612
Diluted (in shares)	93,932	74,176	75,679
Oil income
Operating income:
Royalty income	$ 750,243	$ 619,181	$ 667,281
Natural gas income
Operating income:
Royalty income	14,813	30,953	83,149
Natural gas liquids income
Operating income:
Royalty income	88,520	66,976	87,546
Related Party
Operating income:
Lease bonus income	227	107,823	23,367
Costs and expenses:
General and administrative expenses	10,541	3,696	3,696
Nonrelated Party
Operating income:
Lease bonus income	5,944	1,855	4,424
Costs and expenses:
General and administrative expenses	$ 8,100	$ 6,907	$ 4,846

INCOME TAXES

12 Months Ended

Dec. 31, 2024

Income Tax Disclosure [Abstract]

INCOME TAXES

The Company’s total income tax benefit for the year ended December 31, 2024, 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 years ended December 31, 2023 and 2022, respectively, 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 and effective tax rates for the years ended December 31, 2024, 2023 and 2022 are as follows:


	Year Ended December 31,
	2024			2023			2022
	(In thousands)
Current income tax provision (benefit):
Federal	$	47,264		$	50,414		$	15,929
State	2,110			2,538			1,074
Total current income tax provision (benefit)	49,374			52,952			17,003
Deferred income tax provision (benefit):
Federal	(148,439)			(6,532)			(49,656)
State	(646)			(468)			—
Total deferred income tax provision (benefit)	(149,085)			(7,000)			(49,656)
Total provision (benefit) from income taxes	$	(99,711)		$	45,952		$	(32,653)

Effective tax rates	(19.8)		%	8.4		%	(5.2)		%

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


	Year Ended December 31,
	2024		2023		2022
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	105,826	$	114,931	$	130,694

Impact of nontaxable noncontrolling interest	(51,324)		(63,263)		(105,699)

State income tax expense (benefit), net of federal tax effect	2,028		1,657		846


Change in valuation allowance	(155,908)		(7,281)		(58,443)
Other, net	(333)		(92)		(51)
Provision for (benefit from) income taxes	$	(99,711)	$	45,952	$	(32,653)

The components of the Company’s deferred tax assets and liabilities as of December 31, 2024 and 2023 are as follows:


	Year Ended December 31,
	2024		2023
	(In thousands)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	13	$	15
Investment in the Operating Company	185,228		170,164


Total deferred tax assets	185,241		170,179
Valuation allowance	(6)		(113,523)
Net deferred tax assets	185,235		56,656
Deferred tax liabilities:

Other	386		—
Total deferred tax liabilities	386		—
Net deferred tax assets (liabilities)	$	184,849	$	56,656

At December 31, 2024, the Company has net deferred tax assets of approximately $184.8 million, including immaterial federal capital loss carryforwards expiring in 2026 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.

During the fourth quarter of 2024, the Company released its remaining valuation allowance of $155.9 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 $149.1 million for the year ended December 31, 2024. During the years ended December 31, 2023 and 2022, the Company recognized discrete income tax benefits of $7.0 million and $49.7 million, respectively, 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, Diamondback converted approximately 5.28 million shares of the Company’s Class B Common Stock along with 5.28 million OpCo Units into an equivalent number of shares of Class A Common Stock. In connection with this transaction, the Company recognized a $28.2 million increase in its deferred tax asset and a $10.8 million increase in its valuation allowance through additional paid-in capital.

The Company principally operates in the state of Texas. For the years ended December 31, 2024 and 2023, the Company recognized $2.1 million and $2.5 million, respectively, in state income tax expense primarily for its share of Texas margin tax attributable to the Company’s results which are included in a combined tax return filed by Diamondback. At December 31, 2024, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The Company’s 2021 through 2024 tax years remain open to examination by tax authorities.

The entire disclosure for income tax.

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INCOME TAXES - Schedule of Reconciliation of Statutory Federal Income tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the federal statutory rate (21%)	$ 105,826	$ 114,931	$ 130,694
Impact of nontaxable noncontrolling interest	(51,324)	(63,263)	(105,699)
State income tax expense (benefit), net of federal tax effect	2,028	1,657	846
Change in valuation allowance	(155,908)	(7,281)	(58,443)
Other, net	(333)	(92)	(51)
Total provision (benefit) from income taxes	$ (99,711)	$ 45,952	$ (32,653)

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

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FAIR VALUE MEASUREMENTS - Schedule of Fair Value of Financial Instruments Not Recorded at Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023	Oct. 19, 2023
5.375% Senior Notes due 2027 \| Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated percentage	5.375%
7.375% Senior Notes due 2031
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated percentage			7.375%
7.375% Senior Notes due 2031 \| Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated percentage	7.375%
Carrying Value \| Revolving credit facility \| Line of Credit
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	$ 261,000	$ 263,000
Carrying Value \| 5.375% Senior Notes due 2027 \| Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	427,049	425,949
Carrying Value \| 7.375% Senior Notes due 2031 \| Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	394,930	394,133
Fair Value \| Revolving credit facility \| Line of Credit
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	261,000	263,000
Fair Value \| 5.375% Senior Notes due 2027 \| Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	424,110	422,122
Fair Value \| 7.375% Senior Notes due 2031 \| Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	$ 420,108	$ 418,408

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
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, 2024 segment
Segment Reporting [Abstract]
Number of reportable segments	1
Number of operating segments	1

REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Total royalty income	$ 853,576	$ 717,110	$ 837,976
Revenue Generated from Diamondback Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	458,528	435,132	497,896
Revenue Generated from Third-Party Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	395,048	281,978	340,080
Oil income
Disaggregation of Revenue [Line Items]
Total royalty income	750,243	619,181	667,281
Oil income \| Revenue Generated from Diamondback Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	398,010	376,961	397,282
Oil income \| Revenue Generated from Third-Party Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	352,233	242,220	269,999
Natural gas income
Disaggregation of Revenue [Line Items]
Total royalty income	14,813	30,953	83,149
Natural gas income \| Revenue Generated from Diamondback Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	9,734	16,040	44,232
Natural gas income \| Revenue Generated from Third-Party Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	5,079	14,913	38,917
Natural gas liquids income
Disaggregation of Revenue [Line Items]
Total royalty income	88,520	66,976	87,546
Natural gas liquids income \| Revenue Generated from Diamondback Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	50,784	42,131	56,382
Natural gas liquids income \| Revenue Generated from Third-Party Operated Properties
Disaggregation of Revenue [Line Items]
Total royalty income	$ 37,736	$ 24,845	$ 31,164

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.

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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Cover - USD ($) $ in Billions	12 Months Ended
Cover - USD ($) $ in Billions	Dec. 31, 2024	Feb. 21, 2025	Jun. 30, 2024
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-36505
Entity Registrant Name	Viper Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-5001985
Entity Address, Address Line One	500 West Texas
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			$ 3.4
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Portions of Viper Energy, Inc.’s Proxy Statement for the 2025 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	2024
Document Fiscal Period Focus	FY
Entity Central Index Key	0001602065
Common Class A
Entity Information [Line Items]
Entity Common Shares Outstanding		131,313,142
Common Class B
Entity Information [Line Items]
Entity Common Shares Outstanding		87,831,750

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Net income (loss)	$ 359,245	$ 200,088	$ 151,673

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

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Reference 26: http://www.xbrl.org/2003/role/disclosureRef
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
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Reference 30: http://www.xbrl.org/2003/role/disclosureRef
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Reference 32: http://www.xbrl.org/2003/role/disclosureRef
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Revenue from Contract with Customer [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Royalty Income Receivable, Revenue from Contracts with Customers, Oil and Natural Gas Properties, and Debt Issuance Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2024 USD ($) $ / Boe	Dec. 31, 2023 USD ($) $ / Boe	Dec. 31, 2022 USD ($) $ / Boe	Oct. 19, 2023
Debt Instrument [Line Items]
Royalty income receivable, expected payment period	3 months
Depletion for oil and natural gas properties	$ 214,412	$ 146,118	$ 121,071
Estimated future net revenue discounted rate per annum	10.00%
Debt issuance costs, net of accumulated amortizations	$ 18,300	15,500
Debit issuance costs, accumulated amortization	$ 11,300	$ 10,000
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
7.375% Senior Notes due 2031
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				7.375%
Senior Notes \| 5.375% Senior Notes due 2027
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	5.375%
Senior Notes \| 7.375% Senior Notes due 2031
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	7.375%
Oil and Gas Properties
Debt Instrument [Line Items]
Average depletion rate per barrel equivalent unit of production (usd per BOE) \| $ / Boe	11.77	10.20	9.86
Depletion for oil and natural gas properties	$ 214,400	$ 146,100	$ 121,100

INCOME TAXES - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 13	$ 15
Investment in the Operating Company	185,228	170,164
Total deferred tax assets	185,241	170,179
Valuation allowance	(6)	(113,523)
Net deferred tax assets	185,235	56,656
Deferred tax liabilities:
Other	386	0
Total deferred tax liabilities	386	0
Net deferred tax assets (liabilities)	$ 184,849	$ 56,656

DEBT - Additional Information (Details) - USD ($)		12 Months Ended
DEBT - Additional Information (Details) - USD ($)	Oct. 19, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Nov. 22, 2024	Nov. 21, 2024
Line of Credit Facility [Line Items]
Proceeds from Notes		$ 0	$ 400,000,000	$ 0
7.375% Senior Notes due 2031
Line of Credit Facility [Line Items]
Debt instrument, face amount	$ 400,000,000
Debt instrument, interest rate, stated percentage	7.375%
Proceeds from Notes	$ 394,000,000
Operating Company Revolving Credit Facility \| Revolving credit facility \| Line of Credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity					$ 2,000,000,000.0
Current borrowing capacity					1,300,000,000
Other commitment					$ 1,300,000,000	$ 850,000,000.0
Amount outstanding under credit facility		261,000,000.0
Remaining borrowing capacity		$ 989,000,000.0
Weighted average interest rate		7.34%	7.41%	4.22%
Operating Company Revolving Credit Facility \| Revolving credit facility \| Minimum \| Line of Credit
Line of Credit Facility [Line Items]
Commitment fee on the unused portion of the borrowing base		0.375%
Operating Company Revolving Credit Facility \| Revolving credit facility \| Maximum \| Line of Credit
Line of Credit Facility [Line Items]
Commitment fee on the unused portion of the borrowing base		0.50%
Operating Company Revolving Credit Facility \| Revolving credit facility \| SOFR \| Line of Credit
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.10%
Operating Company Revolving Credit Facility \| Revolving credit facility \| Fed Funds Effective Rate \| Line of Credit
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.50%
Operating Company Revolving Credit Facility \| Revolving credit facility \| 1-month Adjusted Term SOFR \| Line of Credit
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.00%
Operating Company Revolving Credit Facility \| Revolving credit facility \| Base Rate \| Minimum \| Line of Credit
Line of Credit Facility [Line Items]
Debt instrument applicable margin		1.00%
Operating Company Revolving Credit Facility \| Revolving credit facility \| Base Rate \| Maximum \| Line of Credit
Line of Credit Facility [Line Items]
Debt instrument applicable margin		2.00%
Operating Company Revolving Credit Facility \| Revolving credit facility \| Adjusted Term SOFR \| Minimum \| Line of Credit
Line of Credit Facility [Line Items]
Debt instrument applicable margin		2.00%
Operating Company Revolving Credit Facility \| Revolving credit facility \| Adjusted Term SOFR \| Maximum \| Line of Credit
Line of Credit Facility [Line Items]
Debt instrument applicable margin		3.00%

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2024

Schedule of Disaggregation of Revenue


	Year Ended December 31, 2024
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In thousands)
Oil income	$	398,010	$	352,233	$	750,243
Natural gas income	9,734		5,079		14,813
Natural gas liquids income	50,784		37,736		88,520
Total royalty income	$	458,528	$	395,048	$	853,576


	Year Ended December 31, 2023
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In thousands)
Oil income	$	376,961	$	242,220	$	619,181
Natural gas income	16,040		14,913		30,953
Natural gas liquids income	42,131		24,845		66,976
Total royalty income	$	435,132	$	281,978	$	717,110


	Year Ended December 31, 2022
	Revenue Generated from Diamondback Operated Properties		Revenue Generated from Third-Party Operated Properties		Total
	(In thousands)
Oil income	$	397,282	$	269,999	$	667,281
Natural gas income	44,232		38,917		83,149
Natural gas liquids income	56,382		31,164		87,546
Total royalty income	$	497,896	$	340,080	$	837,976

DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2024

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of December 31, 2024, 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.	2025	Puts	20,000	WTI Cushing	$—	$—	$—	$55.00	$(1.62)
Apr. - Jun.	2025	Puts	20,000	WTI Cushing	$—	$—	$—	$55.00	$(1.61)
NATURAL GAS
Jan. - Dec.	2025	Basis Swaps	60,000	Waha Hub	$(0.80)	$—	$—	$—	$—
Jan. - Dec.	2025	Costless Collar	60,000	Henry Hub	$—	$2.50	$4.93	$—	$—

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,
	2024		2023		2022
	(In thousands)
Gain (loss) on derivative instruments(1)	$	11,386	$	(25,793)	$	(18,138)
Net cash receipts (payments) on derivatives(2)	$	(2,978)	$	(13,319)	$	(31,319)

(1)The year ended December 31, 2024 includes an unrealized loss of $3.6 million for the change in fair value of the 2026 WTI Contingent Liability.

(2)The year ended December 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $6.6 million.

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
ORGANIZATION AND BASIS OF PRESENTATION	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION Organization Viper Energy, Inc. (the “Company”) is a publicly traded Delaware corporation focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin. As of December 31, 2024, the Company owned approximately 52% of units representing limited liability company interests (“OpCo Units”) in its operating subsidiary Viper Energy Partners LLC (the “Operating Company”) and was the managing member of the Operating Company. 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, completed an underwritten public offering in which it sold approximately 13.2 million shares of the Company’s Class A Common Stock (the “Diamondback Offering”). Following the Diamondback Offering, Diamondback owned no shares of the Company’s Class A Common Stock and owned 85,431,453 shares of the Company’s Class B Common Stock, reducing its beneficial ownership 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 us, including the services of the executive officers and other employees, substantially in the same manner as those provided to the Company by the former General Partner prior to the Conversion. As of December 31, 2024, Diamondback beneficially owned approximately 45% of the outstanding voting power of the Company’s capital stock. Conversion into Corporation Effective November 13, 2023 (the “Effective Time”), Viper Energy Partners LP (the “Partnership”) converted from a publicly traded Delaware limited partnership to a Delaware corporation pursuant to a plan of conversion (the “Conversion”) and changed names from Viper Energy Partners LP to Viper Energy, Inc. Additionally, the certificate of incorporation and the bylaws of Viper Energy, Inc. became effective. This report includes the results for the Partnership prior to the Conversion and the Company following the Conversion. References to the “Company” refer to (i) Viper Energy, Inc. and its consolidated subsidiaries following the Conversion, and (ii) the Partnership and its consolidated subsidiaries prior to the Conversion. References to shares or per share amounts prior to the Conversion refer to units or per unit amounts. Unless otherwise noted, all references to shares or per share amounts following the Conversion refer to shares or per share amounts of Common Stock, as defined in the paragraph below. References to dividends prior to the Conversion refer to distributions. 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, $0.000001 par value per share (“Class A Common Stock”), of the Company, (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, $0.000001 par value per share, of the Company (“Class B Common Stock” and, together with Class A Common Stock, “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 and was no longer outstanding. At the Effective Time, as a result of the Conversion, holders of common units became holders of Class A Common Stock and holders of Class B units became holders of Class B Common Stock. Similar to Class B units before the Conversion, each share of Class B Common Stock is exchangeable, at the discretion of the holders of Class B Common Stock, together with one unit of the Operating Company, into one share of Class A Common Stock post-Conversion. Holders of Class B Common Stock have the same preferred dividend and liquidation preference rights as those provided to holders of Class B units under the Partnership Agreement. At the Effective Time, Diamondback Energy, Inc. (“Diamondback”) and its wholly owned subsidiary Diamondback E&P LLC were the only holders of the Class B Common Stock and collectively owned approximately 56% of the outstanding shares of Common Stock. At the Effective Time, the Certificate of Incorporation and Bylaws of the Company generally provided stockholders of the Company 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 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 DGCL, 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 a similar manner as Diamondback previously provided to the General Partner. 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. Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“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.

EARNINGS PER COMMON SHARE (Tables)

12 Months Ended

Dec. 31, 2024

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,
	2024		2023		2022
	(In thousands, except per share amounts)
Net income (loss) attributable to the period	$	359,245	$	200,088	$	151,673
Less: net income (loss) allocated to participating securities(1)	583		299		365
Net income (loss) attributable to common stockholders	$	358,662	$	199,789	$	151,308
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	93,932		74,176		75,612
Effect of dilutive securities:
Potential common shares issuable(2)	—		—		67
Diluted weighted average common shares outstanding	93,932		74,176		75,679
Net income (loss) per common share, basic	$	3.82	$	2.69	$	2.00
Net income (loss) per common share, diluted	$	3.82	$	2.69	$	2.00

(1) Unvested restricted stock units and performance restricted stock units that contain non-forfeitable distribution 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 years ended December 31, 2024, 2023 and 2022 no significant potential common shares were excluded from the computation of diluted earnings per common share.

DERIVATIVES

12 Months Ended

Dec. 31, 2024

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

During 2024, the Company used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At December 31, 2024, 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’s counterparties are all participants in the amended and restated credit facility, which is secured by substantially all of the assets of the Operating Company; therefore, the Company is not required to post any collateral. The Company’s counterparties have been determined to have an acceptable credit risk; therefore, the Company does not require collateral from its counterparties. Market risks involved in our use of derivative instruments relate to our potential inability to realize the benefits of any increases in commodity prices above the prices established by our derivative contracts.

As of December 31, 2024, 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.	2025	Puts	20,000	WTI Cushing	$—	$—	$—	$55.00	$(1.62)
Apr. - Jun.	2025	Puts	20,000	WTI Cushing	$—	$—	$—	$55.00	$(1.61)
NATURAL GAS
Jan. - Dec.	2025	Basis Swaps	60,000	Waha Hub	$(0.80)	$—	$—	$—	$—
Jan. - Dec.	2025	Costless Collar	60,000	Henry Hub	$—	$2.50	$4.93	$—	$—

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,
	2024		2023		2022
	(In thousands)
Gain (loss) on derivative instruments(1)	$	11,386	$	(25,793)	$	(18,138)
Net cash receipts (payments) on derivatives(2)	$	(2,978)	$	(13,319)	$	(31,319)

(1)The year ended December 31, 2024 includes an unrealized loss of $3.6 million for the change in fair value of the 2026 WTI Contingent Liability.

(2)The year ended December 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $6.6 million.

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2024

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 2026 WTI Contingent Liability is recorded in “Other long-term liabilities” on the Company’s consolidated balance sheet at December 31, 2024, with the change in fair value being recognized in “Gain (loss) on derivative instruments, net” on the Company’s consolidated statements of operations for the year ended December 31, 2024.

The fair values of the Company’s 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 is estimated using observable market data and a Monte Carlo pricing model, which are considered Level 2 inputs in the fair value hierarchy.

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2024 and December 31, 2023:


	As of December 31, 2024
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	23,816	$	—	$	23,816	$	(6,178)	$	17,638



Liabilities:
Current:
Derivative instruments	$	—	$	8,501	$	—	$	8,501	$	(6,178)	$	2,323
Non-current:

2026 WTI Contingent Liability	$	—	$	29,762	$	—	$	29,762	$	—	$	29,762


	As of December 31, 2023
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	7,040	$	—	$	7,040	$	(6,682)	$	358
Non-current:

Derivative instruments	$	—	$	1,269	$	—	$	1,269	$	(1,177)	$	92
Liabilities:
Current:
Derivative instruments	$	—	$	9,643	$	—	$	9,643	$	(6,682)	$	2,961
Non-current:
Derivative instruments	$	—	$	1,378	$	—	$	1,378	$	(1,177)	$	201

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, 2024				December 31, 2023
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Debt:
Revolving credit facility	$	261,000	$	261,000	$	263,000	$	263,000
5.375% senior notes due 2027(1)	$	427,049	$	424,110	$	425,949	$	422,122
7.375% senior notes due 2031(1)	$	394,930	$	420,108	$	394,133	$	418,408

(1) The carrying value includes associated deferred loan costs and any discount.

The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was 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.

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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SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Future cash inflows	$ 8,322,795	$ 8,493,617	$ 10,072,969
Future production taxes	(578,310)	(593,840)	(729,256)
Future income tax expense	(748,375)	(934,392)	(1,465,160)
Future net cash flows	6,996,110	6,965,385	7,878,553
10% discount to reflect timing of cash flows	(3,676,566)	(3,778,499)	(4,424,457)
Standardized measure of discounted future net cash flows	$ 3,319,544	$ 3,186,886	$ 3,454,096	$ 2,093,117
Viper Energy Inc. \| Diamondback Energy, Inc.
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Percentage by noncontrolling owners	43.00%	51.00%	55.00%

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, 2024 MBoe MBbls MMcf	Dec. 31, 2023 MBoe MBbls MMcf	Dec. 31, 2022 MBoe MBbls MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Total, beginning balance (in MBOE) \| MBoe	179,249	148,900	127,888
Purchase of reserves in place (in MBOE) \| MBoe	14,941	18,977	1,006
Extensions and discoveries (in MBOE) \| MBoe	24,936	25,558	25,858
Revision of previous estimates (in MBOE) \| MBoe	(2,894)	138	8,477
Divestitures (in MBOE) \| MBoe	(2,138)		(2,047)
Production (in MBOE) \| MBoe	(18,221)	(14,324)	(12,282)
Total, ending balance (in MBOE) \| MBoe	195,873	179,249	148,900
Proved developed reserves (in MBOE) \| MBoe	163,865	143,371	107,291
Proved undeveloped reserves (in MBOE) \| MBoe	32,009	35,878	41,609
Non-Controlling Interest
Proved Developed and Undeveloped Reserves [Roll Forward]
Total, beginning balance (in MBOE) \| MBoe	91,417	81,895	69,060
Total, ending balance (in MBOE) \| MBoe	84,226	91,417	81,895
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	89,903	79,004	69,240
Purchase of reserves in place	7,891	10,469	599
Extensions and discoveries	13,099	13,636	15,714
Revisions of previous estimates	(6,472)	(5,178)	1,453
Divestitures	(919)		(905)
Production	(9,939)	(8,028)	(7,097)
End of period	93,563	89,903	79,004
Proved developed reserves (volume)	76,020	69,043	54,817
Proved undeveloped reserve (volume)	17,543	20,860	24,187
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period \| MMcf	263,578	209,964	183,690
Purchase of reserves in place \| MMcf	20,310	27,011	1,186
Extensions and discoveries \| MMcf	33,498	34,632	29,177
Revisions of previous estimates \| MMcf	4,449	11,101	15,248
Divestitures \| MMcf	(4,605)		(3,469)
Production \| MMcf	(24,606)	(19,130)	(15,868)
End of period \| MMcf	292,624	263,578	209,964
Proved developed reserves (volume) \| MMcf	253,271	221,462	161,119
Proved undeveloped reserve (volume) \| MMcf	39,353	42,116	48,845
Natural Gas Liquids
Proved Developed and Undeveloped Reserves [Roll Forward]
Beginning of the period	45,416	34,902	28,033
Purchase of reserves in place	3,665	4,006	209
Extensions and discoveries	6,254	6,150	5,281
Revisions of previous estimates	2,837	3,466	4,483
Divestitures	(451)		(564)
Production	(4,181)	(3,108)	(2,540)
End of period	53,540	45,416	34,902
Proved developed reserves (volume)	45,633	37,417	25,621
Proved undeveloped reserve (volume)	7,907	7,999	9,281

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Schedule of Proved Undeveloped Reserves (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2024 MBoe
Proved Undeveloped Reserves (Energy)
Beginning proved undeveloped reserves at December 31, 2023	35,878
Undeveloped reserves transferred to developed	(16,696)
Revisions	(1,934)
Purchases	4,913
Extensions and discoveries	9,848
Ending proved undeveloped reserves at December 31, 2024	32,009

SEGMENT INFORMATION	12 Months Ended
SEGMENT INFORMATION	Dec. 31, 2024
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION As of December 31, 2024, 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 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—Rev enue from Con tracts 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.

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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STOCKHOLDERS’ EQUITY

12 Months Ended

Dec. 31, 2024

STOCKHOLDERS’ EQUITY

At December 31, 2024, the Company had a total of 102,977,142 shares of Class A Common Stock issued and outstanding and 85,431,453 shares of Class B Common Stock issued and outstanding. At December 31, 2024, all of the issued and outstanding shares of Class B Common Stock were beneficially owned by Diamondback, representing approximately 45% of the Company’s total Common Stock outstanding. Diamondback also beneficially owned 85,431,453 OpCo Units, representing a 43% non-controlling ownership interest in the Operating Company, TWR IV beneficially owned 10,093,670 OpCo Units, representing a 5% non-controlling ownership interest in the Operating Company, and the Company owned the remaining 102,977,142 OpCo Units. The OpCo Units and the Company’s Class B Common Stock beneficially owned by Diamondback are exchangeable from time to time for the Company’s Class A Common Stock (that is, one OpCo Unit and one share of the Company’s Class B Common Stock, together, are exchangeable for one share of the Company’s Class A Common Stock).

In addition to the outstanding shares of the Company’s Class B Common Stock, TWR IV was granted the TWR Class B Option to acquire 10.09 million shares of Class B Common Stock. The OpCo Units and, subject to the exercise of the TWR Class B Option, any shares of Class B Common Stock beneficially owned by TWR IV are under lockup until April 1, 2025, at which time each OpCo Unit and, subject to TWR IV’s exercise of the TWR Class B Option, an equal number of shares of Class B Common Stock will become exchangeable by TWR IV for one share of the Company’s Class A Common Stock. Any shares of Class A Common Stock issued to TWR IV in exchange for OpCo Units and an equal number of shares of Class B Common Stock will reduce the number of shares of Class B Common Stock available to TWR IV under the TWR Class B Option.

2024 Equity Offering

On September 13, 2024, the Company completed an underwritten public offering of approximately 11.50 million shares of its Class A Common Stock, which included 1.50 million 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 $475.9 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 approximately 7.22 million of its common units to Diamondback at a price of $27.72 per unit for total net proceeds of approximately $200.0 million (the “2023 Viper Issuance”). 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.

Common Stock Repurchase Program

The Company’s board of directors has authorized a $750.0 million common stock repurchase program, with respect to the repurchase of the Company’s Class A Common Stock, excluding excise tax, over an indefinite period of time. The Company has and intends to continue to purchase shares of Class A Common Stock 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 from time to time, modified, extended or discontinued by the Company’s board of directors at any time.

During the year ended December 31, 2024, there were no repurchases under the repurchase program. Repurchases of $95.2 million for the year ended December 31, 2023 include approximately $28.7 million for the repurchase of 1.0 million shares of Class A Common Stock from GRP in a privately negotiated transaction in the fourth quarter of 2023. Repurchases of $150.6 million for the year ended December 31, 2022 include approximately $37.3 million for the repurchase of 1.5 million shares of Class A Common Stock from a significant stockholder in a privately negotiated transaction. As of December 31, 2024, $434.2 million remains available under the repurchase program, excluding excise tax.

Changes in Ownership of Consolidated Subsidiaries

Non-controlling interest in the accompanying consolidated financial statements represents Diamondback’s and TWR IV’s ownership 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 Class A Common Stock and distribution 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,
	2024		2023		2022
	(In thousands)
Net income (loss) attributable to the Company	$	359,245	$	200,088	$	151,673
Change in ownership of consolidated subsidiaries	58,713		(101,632)		58,253
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest	$	417,958	$	98,456	$	209,926

Cash Dividends

The board of directors of the Company has established a dividend policy, consistent with the pre-Conversion distribution policy, whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to its unitholders (including Diamondback, the Company and, following the TWR Acquisition completed on October 1, 2024, TWR IV). The Company 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. The Company currently intends to pay quarterly variable dividends of at least 75% of its available cash less the base dividend declared and the amount paid in stock repurchases as part of the Company’s buyback 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’s available cash and the available cash of the Operating Company for each quarter, a non-GAAP measure, is determined by the Company’s board of directors following the end of such quarter. 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), distribution 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 stock 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, 2024, 2023 and 2022 (in thousands, except for per unit amounts):


	Distributions
	(In thousands, except share amounts)
Period	Amount per Operating Company Unit		Operating Company Distributions to Diamondback		Amount per Common Share		Common Unitholders(1)(2)		Declaration Date	Stockholder Record Date	Payment Date
2024
Q4 2023	$	0.69	$	62,590	$	0.56	$	48,337	February 15, 2024	March 5, 2024	March 12, 2024
Q1 2024	$	0.70	$	59,803	$	0.59	$	54,077	April 25, 2024	May 15, 2024	May 22, 2024
Q2 2024	$	0.76	$	64,927	$	0.64	$	58,669	August 1, 2024	August 15, 2024	August 22, 2024
Q3 2024	$	0.73	$	62,366	$	0.61	$	62,932	October 31, 2024	November 14, 2024	November 21, 2024
2023
Q4 2022	$	0.54	$	48,983	$	0.49	$	35,683	February 15, 2023	March 3, 2023	March 10, 2023
Q1 2023	$	0.42	$	38,097	$	0.33	$	23,797	April 26, 2023	May 11, 2023	May 18, 2023
Q2 2023	$	0.44	$	39,912	$	0.36	$	25,563	July 25, 2023	August 10, 2023	August 17, 2023
Q3 2023	$	0.70	$	63,497	$	0.57	$	49,126	November 2, 2023	November 16, 2023	November 24, 2023
2022
Q4 2021	$	0.47	$	42,634	$	0.47	$	36,238	February 16, 2022	March 4, 2022	March 11, 2022
Q1 2022	$	0.70	$	63,497	$	0.67	$	51,680	April 27, 2022	May 12, 2022	May 19, 2022
Q2 2022	$	0.87	$	78,918	$	0.81	$	60,626	July 26, 2022	August 16, 2022	August 23, 2022
Q3 2022	$	0.52	$	47,170	$	0.49	$	36,076	November 3, 2022	November 17, 2022	November 25, 2022

(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.

Cash dividends will be made to the common stockholders of record on the applicable record date, generally within 60 days after the end of each quarter.

Allocation of Net Income

The Partnership, as the previous managing member of the Operating Company, had an agreement, as amended on December 28, 2021, whereby special allocations of the Operating Company’s income and gains over losses and deductions (but before depletion) were made to Diamondback through December 31, 2022. These special income allocations reduced the taxable income allocated to the Partnership’s common unitholders during 2022.

The entire disclosure for equity.

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DEBT - Schedule of Financial Covenants (Details) - Operating Company Revolving Credit Facility - Revolving credit facility - Line of Credit	Dec. 31, 2024
Maximum
Line of Credit Facility [Line Items]
Ratio of total net debt to EBITDAX, as defined in the credit facility	4.0
Ratio of secured debt to EBITDAX, as defined in the credit facility	2.5
Minimum
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit facility	1.0

STOCKHOLDERS’ EQUITY - Schedule of Ownership Interest in Subsidiary Changes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to the Company	$ 359,245	$ 200,088	$ 151,673
Change in ownership of consolidated subsidiaries, net	(20,027)	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	359,245	200,088	151,673
Change in ownership of consolidated subsidiaries, net	58,713	(101,632)	58,253
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest	$ 417,958	$ 98,456	$ 209,926

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

Schedule of Accrued Liabilities

DEBT

12 Months Ended

Dec. 31, 2024

Debt Disclosure [Abstract]

DEBT

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


	December 31,
	2024		2023
	(In thousands)
5.375% Senior Notes due 2027	$	430,350	$	430,350
7.375% Senior Notes due 2031	400,000		400,000
Revolving credit facility	261,000		263,000
Unamortized debt issuance costs	(5,836)		(6,903)
Unamortized discount	(2,535)		(3,365)
Total long-term debt	$	1,082,979	$	1,083,082

Issuance of 2031 Notes

On October 19, 2023, the Company completed an offering of $400.0 million in aggregate principal amount of its 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”). The Company received net proceeds of approximately $394.0 million, after deducting the initial purchasers’ discount and transaction costs from the 2031 Notes. The Company loaned the gross proceeds to the Operating Company, which used the proceeds to partially fund the cash portion of the GRP Acquisition.

The Notes

The Notes are senior unsecured obligations of the Company, initially guaranteed on a senior unsecured basis by the Operating Company, and will pay interest semi-annually. Diamondback will not guarantee the Notes. In the future, each of the Company’s restricted subsidiaries that either (i) guarantees any of its or a guarantor’s indebtedness, or (ii) is a domestic restricted subsidiary and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Notes.

The Operating Company’s Revolving Credit Facility

On November 22, 2024, the Operating Company, as borrower, and the Company, as parent guarantor, entered into a thirteenth amendment to the existing credit facility, which among other things, (i) maintained the maximum credit amount of $2.0 billion, (ii) maintained the borrowing base of $1.3 billion, and (iii) increased the elected commitment amount from $850.0 million to $1.3 billion.

As of December 31, 2024, the Operating Company had $261.0 million of outstanding borrowings and $989.0 million available for future borrowings under the Operating Company’s revolving credit facility. For the years ended December 31, 2024, 2023 and 2022, the weighted average interest rate on borrowings under the Operating Company’s revolving credit facility was 7.34%, 7.41%, and 4.22%, respectively. The revolving credit facility will mature on September 22, 2028.

The outstanding borrowings under the credit facility bear interest at a rate elected by the Operating Company that is equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”), or (ii) 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 Adjusted Term SOFR plus 1.00%), in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternative base rate and from 2.00% to 3.00% per annum in the case of Adjusted Term SOFR, in each case depending on the amount of the loans outstanding in relation to the commitment, which is calculated using the least of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment. The credit facility is secured by substantially all the assets of the Company and the Operating Company.


Financial Covenant						Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit facility						Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit facility						Not less than 1.0 to 1.0
Ratio of secured debt to EBITDAX, as defined in the credit facility						Not greater than 2.5 to 1.0

As of December 31, 2024, the Operating Company was in compliance with all financial maintenance covenants under its credit facility.

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2024, 2023 and 2022:


	Year Ended December 31,
	2024		2023		2022
	(In thousands)
Interest expense	$	74,373	$	48,222	$	37,539
Other fees and expenses	1,529		836		2,883
Less: interest income	2,054		1,666		428


Interest expense, net	$	73,848	$	47,392	$	39,994

SUBSEQUENT EVENTS (Details) $ / shares in Units, $ in Millions	Feb. 14, 2025 USD ($) a bbl / d shares	Feb. 03, 2025 USD ($) $ / shares shares	Jan. 30, 2025 USD ($) a bbl / d well $ / shares shares	Sep. 13, 2024 shares	Dec. 31, 2024
Diamondback Energy, Inc. \| Viper Energy Inc.
Subsequent Event [Line Items]
Subsidiary, ownership percentage, parent					45.00%
Common Class A \| Over-Allotment Option
Subsequent Event [Line Items]
Number of shares sold (in shares)				1,500,000
Subsequent Event \| Diamondback Energy, Inc. \| Viper Energy Inc.
Subsequent Event [Line Items]
Subsidiary, ownership percentage, parent			52.00%
Subsequent Event \| 2025 Equity Offering
Subsequent Event [Line Items]
Sale of stock, consideration received on transaction \| $		$ 1,200.0
Subsequent Event \| Common Class A
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares			$ 0.65
Subsequent Event \| Common Class A \| S 2024 Q4 Quarterly Dividends
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares			0.30
Subsequent Event \| Common Class A \| S 2024 Q4 Variable Dividends
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares			0.35
Subsequent Event \| Common Class A \| 2025 Equity Offering
Subsequent Event [Line Items]
Number of shares sold (in shares)		28,340,000
Shares issued, price per share (usd per share) \| $ / shares		$ 44.50
Subsequent Event \| Common Class A \| Over-Allotment Option
Subsequent Event [Line Items]
Number of shares sold (in shares)		3,700,000
Subsequent Event \| Operating Company Units
Subsequent Event [Line Items]
Dividends declared (usd per share) \| $ / shares			$ 0.69
Morita Ranches \| Subsequent Event
Subsequent Event [Line Items]
Aggregate purchase price \| $	$ 211.0
Net royalty (in acres) \| a	1,691
Average net royalty interest	8.60%
Daily oil production (in barrels per day) \| bbl / d	768
Morita Ranches \| Subsequent Event \| Diamondback Energy, Inc.
Subsequent Event [Line Items]
Percentage of acreage operated by beneficial interest holder	75.00%
Morita Ranches \| Subsequent Event \| Operating Company Units
Subsequent Event [Line Items]
Equity interest issued (in shares)	2,400,000
Endeavor Subsidiaries \| Subsequent Event
Subsequent Event [Line Items]
Net royalty (in acres) \| a			22,847
Average net royalty interest			2.80%
Daily oil production (in barrels per day) \| bbl / d			17,097
Asset acquisition, price of acquisition, expected \| $			$ 1,000.0
Asset acquisition, proved developed production, number of wells, gross \| well			6,055
Asset acquisition, completed production, number of wells, gross \| well			116
Asset acquisition, uncompleted production well, number of wells, gross \| well			394
Endeavor Subsidiaries \| Subsequent Event \| Diamondback Energy, Inc.
Subsequent Event [Line Items]
Percentage of acreage operated by beneficial interest holder			69.00%
Percentage of wells operated by beneficial interest holder			29.00%
Endeavor Subsidiaries \| Subsequent Event \| Common Class A
Subsequent Event [Line Items]
Asset acquisition, number of shares upon conversion			1
Endeavor Subsidiaries \| Subsequent Event \| Operating Company Units
Subsequent Event [Line Items]
Equity interest issued (in shares)			69,630,000
Asset acquisition, number of units called for conversion (in shares)			1
Endeavor Subsidiaries \| Subsequent Event \| Common Class B
Subsequent Event [Line Items]
Asset acquisition, number of shares called for conversion			1

Insider Trading Policies and Procedures	12 Months Ended
Insider Trading Policies and Procedures	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

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 Thousands	Dec. 31, 2024	Dec. 31, 2023
Oil and natural gas interests:
Proved	$ 3,532,834	$ 2,859,642
Unproved	2,179,837	1,769,341
Total oil and natural gas interests	5,712,671	4,628,983
Accumulated depletion and impairment	(1,080,764)	(866,352)
Net oil and natural gas interests capitalized	$ 4,631,907	$ 3,762,631

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2024
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States (“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 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 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 financial statements. 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, the war in Ukraine, the Israel-Hamas War and other conflicts in the Middle East, higher interest rates, global supply chain disruptions, and recent measures to combat persistent inflation and instability in the financial sector have contributed to recent pricing and economic 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 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 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, the fair value determination of assets and liabilities, including those acquired by the Company, fair value estimates of commodity derivatives and estimates of income taxes, including deferred tax valuation allowances.
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.
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.
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 the 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.”
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. 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 producer 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, and as a result, the Company is required to estimate the amount of royalty income to be received based upon the Company’s 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 producer. 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	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 are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas 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 liquids and natural gas. At December 31, 2024 and 2023, the Company’s oil and natural gas properties consist solely 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 $11.77, $10.20 and $9.86 for the years ended December 31, 2024, 2023 and 2022, respectively. Depletion for oil and natural gas properties was $214.4 million, $146.1 million and $121.1 million for the years ended December 31, 2024, 2023 and 2022, 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 and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (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, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Debt Issuance Costs	Debt Issuance Costs Other assets include capitalized costs related to the credit facility of $18.3 million and $15.5 million, and accumulated amortization of those costs over the term of the credit facility of $11.3 million and $10.0 million as of December 31, 2024, and 2023, respectively. Long-term debt includes capitalized costs related to the Company’s 5.375% senior notes due 2027 and 7.375% senior notes due 2031 (collectively, the “Notes”). The costs associated with the Notes are being netted against the Notes’ balances and amortized over the term of the Notes using the effective interest method. See Note 6—Debt for further details.
Concentrations	Concentrations The Company is subject to risk resulting from the concentration of the Company’s royalty income in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2024, no purchaser accounted for more than 10% of royalty income. For the year ended December 31, 2023, two purchasers each accounted for more than 10% of royalty income: Vitol Midstream Pipeline LLC (16%) and DK Trading and Supply LLC (15%). For the year ended December 31, 2022, two purchasers each accounted for more than 10% of royalty income: Shell Trading (US) Company (14%) and Vitol Midstream Pipeline LLC (14%). 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.
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. During the years ended December 31, 2024, 2023 and 2022, 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 Non-controlling interest in the accompanying consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. When Diamondback’s relative ownership interest 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.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently Adopted Pronouncements In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures,” which updates reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments are effective for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. The amendments should be applied retrospectively to all prior periods presented in the financial statements. Adoption of the update did not impact the Company’s financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted 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 amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should 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. 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.
Revenue from Contract with Customer	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.
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 2026 WTI Contingent Liability is recorded in “Other long-term liabilities” on the Company’s consolidated balance sheet at December 31, 2024, with the change in fair value being recognized in “Gain (loss) on derivative instruments, net” on the Company’s consolidated statements of operations for the year ended December 31, 2024. The fair values of the Company’s 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 is estimated using observable market data and a Monte Carlo pricing model, which are considered Level 2 inputs in the fair value hierarchy.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations (Details) - Customer Concentration Risk - Royalty Interest Revenue	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Vitol Midstream Pipeline LLC
Concentration Risk [Line Items]
Percent of total royalty interest revenue	16.00%	14.00%
DK Trading and Supply LLC
Concentration Risk [Line Items]
Percent of total royalty interest revenue	15.00%
Shell Trading
Concentration Risk [Line Items]
Percent of total royalty interest revenue		14.00%

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Interest payable	$ 9,911	$ 11,036
Ad valorem taxes payable	19,813	13,299
Derivatives instruments payable	1,177	1,279
Acquisition adjustment accrual	8,627	35
Other	2,744	1,372
Total accrued liabilities	$ 42,272	$ 27,021

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2024
Audit Information [Abstract]
Auditor Firm ID	248
Auditor Name	GRANT THORNTON LLP
Auditor Location	Oklahoma City, Oklahoma

EARNINGS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
Net income (loss)	$ 359,245	$ 200,088	$ 151,673
Less: net income (loss) allocated to participating securities	583	299	365
Net income (loss) attributable to common stockholders	$ 358,662	$ 199,789	$ 151,308
Basic weighted average common shares outstanding (in shares)	93,932,000	74,176,000	75,612,000
Effect of dilutive securities:
Potential common shares issuable (in shares)	0	0	67,000
Diluted weighted average common shares outstanding (in shares)	93,932,000	74,176,000	75,679,000
Net income (loss) per common share, basic (usd per share)	$ 3.82	$ 2.69	$ 2.00
Net income (loss) per common share, diluted (usd per share)	$ 3.82	$ 2.69	$ 2.00
Antidilutive securities, restricted stock units (in shares)	0	0	0

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, 2024 $ / bbl $ / Mcf	Dec. 31, 2023 $ / bbl $ / Mcf	Dec. 31, 2022 $ / bbl $ / Mcf
Oil
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)	75.61	77.93	95.04
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	0.49	1.54	5.74
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)	20.62	23.79	38.95

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2024

Accounting Policies [Abstract]

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


	December 31,
	2024		2023
	(In thousands)
Interest payable	$	9,911	$	11,036
Ad valorem taxes payable	19,813		13,299
Derivatives instruments payable	1,177		1,279
Acquisition adjustment accrual	8,627		35
Other	2,744		1,372
Total accrued liabilities	$	42,272	$	27,021

EARNINGS PER COMMON SHARE

12 Months Ended

Dec. 31, 2024

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, 2024 and 2023 and common units for the year ended December 31, 2022. For the year ended December 31, 2022, the Partnership’s net income (loss) was allocated wholly to the common unitholders, as the General Partner did not have an economic interest. Payments made to the Company’s stockholders are determined in relation to the cash dividend policy described in Note 7—Stockholders' Equity.

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,
	2024		2023		2022
	(In thousands, except per share amounts)
Net income (loss) attributable to the period	$	359,245	$	200,088	$	151,673
Less: net income (loss) allocated to participating securities(1)	583		299		365
Net income (loss) attributable to common stockholders	$	358,662	$	199,789	$	151,308
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	93,932		74,176		75,612
Effect of dilutive securities:
Potential common shares issuable(2)	—		—		67
Diluted weighted average common shares outstanding	93,932		74,176		75,679
Net income (loss) per common share, basic	$	3.82	$	2.69	$	2.00
Net income (loss) per common share, diluted	$	3.82	$	2.69	$	2.00

(2) For the years ended December 31, 2024, 2023 and 2022 no significant potential common shares were excluded from the computation of diluted earnings per common share.

ACQUISITIONS AND DIVESTITURES	12 Months Ended
ACQUISITIONS AND DIVESTITURES	Dec. 31, 2024
Business Combinations And Divestitures [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 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”) as defined and discussed below. TWR Acquisition On October 1, 2024, (the “TWR Closing Date”), the Company acquired all of the issued and outstanding equity interests in TWR IV, LLC and TWR IV SellCo, LLC from Tumbleweed Royalty IV, LLC (“TWR IV”) and TWR IV SellCo Parent, LLC (the “TWR Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of approximately (i) $464.2 million in cash, including transaction costs and certain customary post-closing adjustments, (ii) 10.09 million OpCo Units to TWR IV, (iii) an option (the “TWR Class B Option”) granted to TWR IV to acquire up to 10.09 million shares of the Company’s Class B Common Stock, and (iv) contingent cash consideration of up to $41.0 million, payable in January of 2026, based on the average price of WTI sweet crude oil prompt month futures contracts for the calendar year 2025 (the “WTI 2025 Average”). The contingent cash consideration payment will be (i) $16.4 million if the WTI 2025 Average is between $60.00 and $65.00, (ii) $24.6 million if the WTI 2025 Average is between $65.00 and $75.00, or (iii) $41.0 million if the WTI 2025 Average is greater than $75.00. The Company recorded the contingent cash consideration at its fair value of $21.3 million on the TWR Closing Date (the “TWR Contingent Liability”). Additionally, at the closing of the TWR Acquisition, the Company assumed from TWR IV a royalty income receivable of approximately $24.3 million. TWR IV can exchange some or all of the OpCo Units received for an equal number of shares of Class A Common Stock upon expiration of a six month lockup period, and any OpCo Units so exchanged will reduce the number of shares of Class B Common Stock subject to the TWR Class B Option. 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 the Operating Company’s 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 “Q Closing Date”), 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 $114.0 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of up to $5.4 million, payable in January of 2026, based on the WTI 2025 Average. The contingent cash consideration payment will be (i) $2.2 million if the WTI 2025 Average is between $60.00 and $65.00, (ii) $3.2 million if the WTI 2025 Average is between $65.00 and $75.00, or (iii) $5.4 million if the WTI 2025 Average is greater than $75.00. The Company recorded the contingent cash consideration at its fair value of $2.9 million on the Q Closing Date (the “Q Contingent Liability”). 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 the Operating Company’s revolving credit facility. M Acquisition On September 3, 2024 (the “M Closing Date”), 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 $76.1 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of up to $3.6 million, payable in January of 2026, based on the WTI 2025 Average. The contingent cash consideration payment will be (i) $1.4 million if the WTI 2025 Average is between $60.00 and $65.00, (ii) $2.2 million if the WTI 2025 Average is between $65.00 and $75.00, or (iii) $3.6 million if the WTI 2025 Average is greater than $75.00. The Company recorded the contingent cash consideration at its fair value of $1.9 million on the M Closing Date (the “M Contingent Liability”). 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 the Operating Company’s revolving credit facility. At December 31, 2024, the aggregate estimated fair value of the Q Contingent Liability, the M Contingent Liability and the TWR Contingent Liability, (collectively, the “2026 WTI Contingent Liability“) was $29.8 million. See Note 10—Derivatives and Note 11—Fair Value Measurements for further discussion of the fair value of the 2026 WTI Contingent Liability. Other Acquisitions Additionally 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 $54.2 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under the Operating Company’s 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 $87.2 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 approximately 9.02 million common units and $747.5 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, plus 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 the Operating Company’s revolving credit facility, proceeds from the 2031 Notes (as defined in Note 6—Debt) and proceeds from the $200.0 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 $74.5 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 represent approximately 660 net royalty acres in Ward County in the Southern Delaware Basin, 100% of which are operated by Diamondback, and have an average net royalty interest of approximately 7.2% and current production of approximately 300 BO/d. The Company funded the 2023 Drop Down through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. The 2023 Drop Down was accounted for as a transaction between entities under common control with the properties acquired 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 $70.4 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility. 2022 Acquisitions Acquisitions During the year ended December 31, 2022, in individually insignificant transactions, the Company acquired from unrelated third-party sellers mineral and royalty interests representing 375 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $65.8 million, including customary closing adjustments. The Company funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility. Divestitures In the fourth quarter of 2022, the Company divested its entire position in the Eagle Ford Shale consisting of 681 net royalty acres of third-party operated acreage for an aggregate net sales price of $53.7 million, including customary closing adjustments. In the third quarter of 2022, the Company divested 93 net royalty acres of third-party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate net sales price of $29.9 million, including customary closing adjustments. In the first quarter of 2022, the Company divested 325 net royalty acres of third-party operated acreage located entirely in Upton and Reagan counties in the Midland Basin for an aggregate net sales price of $29.3 million, including customary closing adjustments.

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

12 Months Ended

Dec. 31, 2024

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,
	2024		2023
	(In thousands)
Oil and natural gas interests:
Proved	$	3,532,834	$	2,859,642
Unproved	2,179,837		1,769,341
Total oil and natural gas interests	5,712,671		4,628,983
Accumulated depletion and impairment	(1,080,764)		(866,352)
Net oil and natural gas interests capitalized	$	4,631,907	$	3,762,631

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,
	2024		2023		2022
	(In thousands)
Acquisition costs:
Proved properties	$	340,907	$	402,659	$	46,307
Unproved properties	830,450		758,342		16,624
Total	$	1,171,357	$	1,161,001	$	62,931

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” above.

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers, as of December 31, 2024, 2023 and 2022. 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, 2024, 2023 and 2022, 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, development expenditures, operating expenses 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, 2021	69,240	183,690	28,033	127,888
Purchase of reserves in place	599	1,186	209	1,006
Extensions and discoveries	15,714	29,177	5,281	25,858
Revisions of previous estimates	1,453	15,248	4,483	8,477
Divestitures	(905)	(3,469)	(564)	(2,047)
Production	(7,097)	(15,868)	(2,540)	(12,282)
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

Proved Developed Reserves:
December 31, 2022	54,817	161,119	25,621	107,291
December 31, 2023	69,043	221,462	37,417	143,371
December 31, 2024	76,020	253,271	45,633	163,865

Proved Undeveloped Reserves:
December 31, 2022	24,187	48,845	9,281	41,609
December 31, 2023	20,860	42,116	7,999	35,878
December 31, 2024	17,543	39,353	7,907	32,009

(1) Includes total proved reserves of 84,226 MBOE, 91,417 MBOE, 81,895 MBOE and 69,060 MBOE as of December 31, 2024, 2023, 2022 and 2021, respectively, attributable to a non-controlling interest in the 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, 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.

During the year ended December 31, 2022, the Company’s total extensions and discoveries of 25,858 MBOE resulted primarily from the drilling of 636 new wells and from 199 new proved undeveloped locations added. The Company’s total positive revisions of previous estimated quantities of 8,477 MBOE were due to positive revisions of 15,484 MBOE attributable to price and performance revisions which were partially offset by PUD downgrades of 7,007 MBOE. Total purchases of reserves in place of 1,006 MBOE resulted from multiple acquisitions of certain mineral and royalty interests.

Proved Undeveloped Reserves

As of December 31, 2024, the Company’s PUD reserves totaled 17,543 MBbls of oil, 39,353 MMcf of natural gas and 7,907 MBbls of natural gas liquids, for a total of 32,009 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. The Company’s PUD reserves were from 837 horizontal wells, all of which Diamondback operates. Of the horizontal locations, 219 are Middle Spraberry/Jo Mill wells, 212 are Wolfcamp A wells, 195 are Lower Spraberry wells, 144 are Wolfcamp B wells, 44 are Bone Spring wells, 16 are Dean wells and seven are Wolfcamp D wells.

The following table includes the changes in PUD reserves for 2024:


			(MBOE)
Beginning proved undeveloped reserves at December 31, 2023			35,878
Undeveloped reserves transferred to developed			(16,696)
Revisions			(1,934)
Purchases			4,913

Extensions and discoveries			9,848
Ending proved undeveloped reserves at December 31, 2024			32,009

The decrease in PUD reserves was primarily attributable to the conversion of 16,696 MBOE of PUD reserves into proved developed reserves and downward revisions of 1,934 MBOE primarily attributable to PUD downgrades of 2,642 MBOE. These reductions in PUD reserves were partially offset by positive additions of 9,848 MBOE, primarily from 447 new horizontal well locations attributable to extensions resulting from strategic drilling of wells to delineate our acreage position and acquisitions of 4,913 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, 2024, 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; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

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, 2024, 2023 and 2022:


	December 31,
	2024		2023		2022
	(In thousands)
Future cash inflows	$	8,322,795	$	8,493,617	$	10,072,969
Future production taxes	(578,310)		(593,840)		(729,256)
Future income tax expense	(748,375)		(934,392)		(1,465,160)
Future net cash flows	6,996,110		6,965,385		7,878,553
10% discount to reflect timing of cash flows	(3,676,566)		(3,778,499)		(4,424,457)
Standardized measure of discounted future net cash flows(1)	$	3,319,544	$	3,186,886	$	3,454,096

(1) Includes a 43%, 51% and 55% non-controlling interest in the Company at December 31, 2024, 2023 and 2022, 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,
	2024		2023		2022


Oil (per Bbl)	$	75.61	$	77.93	$	95.04
Natural gas (per Mcf)	$	0.49	$	1.54	$	5.74
Natural gas liquids (per Bbl)	$	20.62	$	23.79	$	38.95

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,
	2024		2023		2022
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	3,186,886	$	3,454,096	$	2,093,117
Purchase of minerals in place	354,874		473,742		30,331
Divestiture of reserves	(51,119)		—		(30,076)
Sales of oil and natural gas, net of production costs	(792,694)		(666,709)		(781,604)
Extensions and discoveries	640,438		626,854		844,010
Net changes in prices and production costs	(438,456)		(1,405,205)		1,131,202
Revisions of previous quantity estimates	(84,949)		2,726		309,338
Net changes in income taxes	70,333		212,391		(393,652)
Accretion of discount	373,790		427,998		234,717
Net changes in timing of production and other	60,441		60,993		16,713
Standardized measure of discounted future net cash flows at the end of the period	$	3,319,544	$	3,186,886	$	3,454,096

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.

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
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-Paragraph 3
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-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
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-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

Schedule of Components of the Provision for Income Taxes

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2024

Income Tax Disclosure [Abstract]

The components of the provision for income taxes and effective tax rates for the years ended December 31, 2024, 2023 and 2022 are as follows:


	Year Ended December 31,
	2024			2023			2022
	(In thousands)
Current income tax provision (benefit):
Federal	$	47,264		$	50,414		$	15,929
State	2,110			2,538			1,074
Total current income tax provision (benefit)	49,374			52,952			17,003
Deferred income tax provision (benefit):
Federal	(148,439)			(6,532)			(49,656)
State	(646)			(468)			—
Total deferred income tax provision (benefit)	(149,085)			(7,000)			(49,656)
Total provision (benefit) from income taxes	$	(99,711)		$	45,952		$	(32,653)

Effective tax rates	(19.8)		%	8.4		%	(5.2)		%

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,
	2024		2023		2022
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (21%)	$	105,826	$	114,931	$	130,694

Impact of nontaxable noncontrolling interest	(51,324)		(63,263)		(105,699)

State income tax expense (benefit), net of federal tax effect	2,028		1,657		846


Change in valuation allowance	(155,908)		(7,281)		(58,443)
Other, net	(333)		(92)		(51)
Provision for (benefit from) income taxes	$	(99,711)	$	45,952	$	(32,653)

Schedule of Deferred Tax Assets and Liabilities

The components of the Company’s deferred tax assets and liabilities as of December 31, 2024 and 2023 are as follows:


	Year Ended December 31,
	2024		2023
	(In thousands)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	13	$	15
Investment in the Operating Company	185,228		170,164


Total deferred tax assets	185,241		170,179
Valuation allowance	(6)		(113,523)
Net deferred tax assets	185,235		56,656
Deferred tax liabilities:

Other	386		—
Total deferred tax liabilities	386		—
Net deferred tax assets (liabilities)	$	184,849	$	56,656

DERIVATIVES - Schedule of Open Derivative Positions (Details) - 2025 bbl / d in Thousands, MMBTU in Thousands	12 Months Ended
	Dec. 31, 2024 bbl / d MMBTU $ / bbl $ / MMBTU
OIL \| WTI Cushing \| Puts \| Jan. - Mar.
Derivative [Line Items]
Bbls Per Day (in barrels per day) \| bbl / d	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	55.00
Deferred Premium (usd per bbls/mmbtu) \| $ / bbl	(1.62)
OIL \| WTI Cushing \| Puts \| Apr. - Jun.
Derivative [Line Items]
Bbls Per Day (in barrels per day) \| bbl / d	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	55.00
Deferred Premium (usd per bbls/mmbtu) \| $ / bbl	(1.61)
NATURAL GAS \| Waha Hub \| Basis Swaps \| Jan. - Dec.
Derivative [Line Items]
MMBtu Per Day (in mmbtu) \| MMBTU	60
Weighted Average Differential (usd per bbls) \| $ / MMBTU	(0.80)
Weighted Average Floor Price (usd per bbls/mmbtu) \| $ / MMBTU	0
Weighted Average Ceiling Price (usd per bbls/mmbtu) \| $ / MMBTU	0
Strike Price (usd per bbls/mmbtu) \| $ / MMBTU	0
Deferred Premium (usd per bbls/mmbtu) \| $ / MMBTU	0
NATURAL GAS \| Henry Hub \| Costless Collar \| Jan. - Dec.
Derivative [Line Items]
MMBtu Per Day (in mmbtu) \| MMBTU	60
Weighted Average Differential (usd per bbls) \| $ / MMBTU	0
Weighted Average Floor Price (usd per bbls/mmbtu) \| $ / MMBTU	2.50
Weighted Average Ceiling Price (usd per bbls/mmbtu) \| $ / MMBTU	4.93
Strike Price (usd per bbls/mmbtu) \| $ / MMBTU	0
Deferred Premium (usd per bbls/mmbtu) \| $ / MMBTU	0

DEBT - Schedule of Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Interest expense	$ 74,373	$ 48,222	$ 37,539
Other fees and expenses	1,529	836	2,883
Less: interest income	2,054	1,666	428
Interest expense, net	$ 73,848	$ 47,392	$ 39,994

STOCKHOLDERS’ EQUITY (Tables)

12 Months Ended

Dec. 31, 2024

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,
	2024		2023		2022
	(In thousands)
Net income (loss) attributable to the Company	$	359,245	$	200,088	$	151,673
Change in ownership of consolidated subsidiaries	58,713		(101,632)		58,253
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest	$	417,958	$	98,456	$	209,926

Schedule of Dividends Declared

The following table presents information regarding cash distributions and dividends paid during the years ended December 31, 2024, 2023 and 2022 (in thousands, except for per unit amounts):


	Distributions
	(In thousands, except share amounts)
Period	Amount per Operating Company Unit		Operating Company Distributions to Diamondback		Amount per Common Share		Common Unitholders(1)(2)		Declaration Date	Stockholder Record Date	Payment Date
2024
Q4 2023	$	0.69	$	62,590	$	0.56	$	48,337	February 15, 2024	March 5, 2024	March 12, 2024
Q1 2024	$	0.70	$	59,803	$	0.59	$	54,077	April 25, 2024	May 15, 2024	May 22, 2024
Q2 2024	$	0.76	$	64,927	$	0.64	$	58,669	August 1, 2024	August 15, 2024	August 22, 2024
Q3 2024	$	0.73	$	62,366	$	0.61	$	62,932	October 31, 2024	November 14, 2024	November 21, 2024
2023
Q4 2022	$	0.54	$	48,983	$	0.49	$	35,683	February 15, 2023	March 3, 2023	March 10, 2023
Q1 2023	$	0.42	$	38,097	$	0.33	$	23,797	April 26, 2023	May 11, 2023	May 18, 2023
Q2 2023	$	0.44	$	39,912	$	0.36	$	25,563	July 25, 2023	August 10, 2023	August 17, 2023
Q3 2023	$	0.70	$	63,497	$	0.57	$	49,126	November 2, 2023	November 16, 2023	November 24, 2023
2022
Q4 2021	$	0.47	$	42,634	$	0.47	$	36,238	February 16, 2022	March 4, 2022	March 11, 2022
Q1 2022	$	0.70	$	63,497	$	0.67	$	51,680	April 27, 2022	May 12, 2022	May 19, 2022
Q2 2022	$	0.87	$	78,918	$	0.81	$	60,626	July 26, 2022	August 16, 2022	August 23, 2022
Q3 2022	$	0.52	$	47,170	$	0.49	$	36,076	November 3, 2022	November 17, 2022	November 25, 2022

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

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2024

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s 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 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 financial statements.

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, the war in Ukraine, the Israel-Hamas War and other conflicts in the Middle East, higher interest rates, global supply chain disruptions, and recent measures to combat persistent inflation and instability in the financial sector have contributed to recent pricing and economic 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 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 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, the fair value determination of assets and liabilities, including those acquired by the Company, fair value estimates of commodity derivatives and estimates of income taxes, including deferred tax valuation allowances.

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.

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, 2024 and December 31, 2023, the Company’s allowance for expected losses was immaterial.

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 the 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.”

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.

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 producer 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, and as a result, the Company is required to estimate the amount of royalty income to be received based upon the Company’s 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 producer. 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 are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas 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 liquids and natural gas. At December 31, 2024 and 2023, the Company’s oil and natural gas properties consist solely 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 $11.77, $10.20 and $9.86 for the years ended December 31, 2024, 2023 and 2022, respectively. Depletion for oil and natural gas properties was $214.4 million, $146.1 million and $121.1 million for the years ended December 31, 2024, 2023 and 2022, 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 and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (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, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Debt Issuance Costs

Other assets include capitalized costs related to the credit facility of $18.3 million and $15.5 million, and accumulated amortization of those costs over the term of the credit facility of $11.3 million and $10.0 million as of December 31, 2024, and 2023, respectively.

Long-term debt includes capitalized costs related to the Company’s 5.375% senior notes due 2027 and 7.375% senior notes due 2031 (collectively, the “Notes”). The costs associated with the Notes are being netted against the Notes’ balances and amortized over the term of the Notes using the effective interest method. See Note 6—Debt for further details.

Related Party Transactions

Royalty Income Receivable

As of December 31, 2024 and December 31, 2023, Diamondback, either directly or through its consolidated subsidiaries, owed the Company $31.0 million and $3.3 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, 2024, Diamondback E&P LLC paid the Operating Company $0.2 million of lease bonus income primarily related to new leases in the Midland Basin. During the year ended December 31, 2023, Diamondback E&P LLC paid the Operating Company $107.8 million of lease bonus income, which includes a lease bonus payment of $95.8 million from a lease agreement with a subsidiary of Diamondback covering certain Permian Basin acreage on terms substantially identical to the Operating Company’s other lease arrangements with Diamondback. This transaction was considered and approved by the conflicts committee of the board of directors. During the year ended December 31, 2022, Diamondback, either directly or through its consolidated subsidiaries, paid the Company $23.4 million of lease bonus income primarily related to lease ratification and certain leases acquired in 2021.

Other Related Party Transactions

See Note 4—Acquisitions and Divestitur es and Note 13—Subsequent Events 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, 2024, 2023 and 2022, respectively.

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,
	2024		2023
	(In thousands)
Interest payable	$	9,911	$	11,036
Ad valorem taxes payable	19,813		13,299
Derivatives instruments payable	1,177		1,279
Acquisition adjustment accrual	8,627		35
Other	2,744		1,372
Total accrued liabilities	$	42,272	$	27,021

Concentrations

The Company is subject to risk resulting from the concentration of the Company’s royalty income in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2024, no purchaser accounted for more than 10% of royalty income. For the year ended December 31, 2023, two purchasers each accounted for more than 10% of royalty income: Vitol Midstream Pipeline LLC (16%) and DK Trading and Supply LLC (15%). For the year ended December 31, 2022, two purchasers each accounted for more than 10% of royalty income: Shell Trading (US) Company (14%) and Vitol Midstream Pipeline LLC (14%). 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.

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, 2024, 2023 and 2022, 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 Diamondback’s ownership in the net assets of the Operating Company. When Diamondback’s relative ownership interest 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.

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures,” which updates reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments are effective for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. The amendments should be applied retrospectively to all prior periods presented in the financial statements. Adoption of the update did not impact the Company’s financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

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 amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should 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.

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.

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Not subject to depletion	$ 2,179,837	$ 1,769,341
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)	102,977,142	86,144,273
Common stock outstanding (in shares)	102,977,142	86,144,273
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)	85,431,453	90,709,946
Common stock outstanding (in shares)	85,431,453	90,709,946

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Diamondback Energy, Inc.
Related Party Transaction [Line Items]
Lease bonus income		$ 95.8
Affiliated Entity \| Royalty Income Receivable
Related Party Transaction [Line Items]
Royalty income receivable	$ 31.0	3.3
Affiliated Entity \| Lease Bonus Income
Related Party Transaction [Line Items]
Related party transaction, amounts of transaction	$ 0.2	$ 107.8	$ 23.4

ORGANIZATION AND BASIS OF PRESENTATION (Details)

1 Months Ended

12 Months Ended

Mar. 08, 2024

Nov. 13, 2023

director

$ / shares

Mar. 31, 2024

Dec. 31, 2024

segment

$ / shares

Dec. 31, 2023

$ / shares

Nov. 12, 2023

Dec. 31, 2022

^[2]

Organization, Consolidation and Presentation of Financial Statements [Line Items]

100.00%

Designated board members (up to) | director

Number of reportable segments | segment

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]

Organization, Consolidation and Presentation of Financial Statements [Line Items]

25.00%

Maximum

Designated board members (up to) | director

Common Class A

Organization, Consolidation and Presentation of Financial Statements [Line Items]

102,977,142

86,144,273

Common stock par value (usd per share) | $ / shares

$ 0.000001

Common Class A | Common Stock

Organization, Consolidation and Presentation of Financial Statements [Line Items]

Common Class A | Diamondback Energy, Inc.

102,977,000

^[1]

86,144,000

^[1],[2]

Organization, Consolidation and Presentation of Financial Statements [Line Items]

Common Class A | Diamondback Offering | Diamondback Energy, Inc.

7,946,507

Organization, Consolidation and Presentation of Financial Statements [Line Items]

Number of shares sold (in shares)

13,200,000

Common Class B

Organization, Consolidation and Presentation of Financial Statements [Line Items]

85,431,453

90,709,946

56.00%

Common stock par value (usd per share) | $ / shares

5,280,000

$ 0.000001

Common Class B | Common Stock

Organization, Consolidation and Presentation of Financial Statements [Line Items]

Common Class B | Diamondback Energy, Inc.

85,431,000

^[1]

90,710,000

^[1],[2]

Organization, Consolidation and Presentation of Financial Statements [Line Items]

Organization, Consolidation and Presentation of Financial Statements [Line Items]

85,431,453

Operating Company Units

Viper Energy Partners LLC

5,280,000

Organization, Consolidation and Presentation of Financial Statements [Line Items]

Subsidiary, ownership percentage, parent

52.00%

Viper Energy Partners LLC | Operating Company Units | Diamondback Energy, Inc.

Organization, Consolidation and Presentation of Financial Statements [Line Items]

85,431,453

Viper Energy Inc. | Diamondback Energy, Inc.

43.00%

Organization, Consolidation and Presentation of Financial Statements [Line Items]

Subsidiary, ownership percentage, parent

45.00%

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

50.00%

[1]	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.
[2]	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.

DEBT - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023	Oct. 19, 2023
Line of Credit Facility [Line Items]
Unamortized debt issuance costs	$ (5,836)	$ (6,903)
Unamortized discount	(2,535)	(3,365)
Total long-term debt	1,082,979	1,083,082
Revolving credit facility \| Line of Credit
Line of Credit Facility [Line Items]
Long term debt gross	$ 261,000	263,000
5.375% Senior Notes due 2027 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	5.375%
Long term debt gross	$ 430,350	430,350
7.375% Senior Notes due 2031
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage			7.375%
7.375% Senior Notes due 2031 \| Senior Notes
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	7.375%
Long term debt gross	$ 400,000	$ 400,000

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2024

Fair Value Disclosures [Abstract]


	As of December 31, 2024
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	23,816	$	—	$	23,816	$	(6,178)	$	17,638



Liabilities:
Current:
Derivative instruments	$	—	$	8,501	$	—	$	8,501	$	(6,178)	$	2,323
Non-current:

2026 WTI Contingent Liability	$	—	$	29,762	$	—	$	29,762	$	—	$	29,762


	As of December 31, 2023
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	7,040	$	—	$	7,040	$	(6,682)	$	358
Non-current:

Derivative instruments	$	—	$	1,269	$	—	$	1,269	$	(1,177)	$	92
Liabilities:
Current:
Derivative instruments	$	—	$	9,643	$	—	$	9,643	$	(6,682)	$	2,961
Non-current:
Derivative instruments	$	—	$	1,378	$	—	$	1,378	$	(1,177)	$	201

Schedule of Offsetting Liabilities


	As of December 31, 2024
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	23,816	$	—	$	23,816	$	(6,178)	$	17,638



Liabilities:
Current:
Derivative instruments	$	—	$	8,501	$	—	$	8,501	$	(6,178)	$	2,323
Non-current:

2026 WTI Contingent Liability	$	—	$	29,762	$	—	$	29,762	$	—	$	29,762


	As of December 31, 2023
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	7,040	$	—	$	7,040	$	(6,682)	$	358
Non-current:

Derivative instruments	$	—	$	1,269	$	—	$	1,269	$	(1,177)	$	92
Liabilities:
Current:
Derivative instruments	$	—	$	9,643	$	—	$	9,643	$	(6,682)	$	2,961
Non-current:
Derivative instruments	$	—	$	1,378	$	—	$	1,378	$	(1,177)	$	201

Schedule of Offsetting Assets


	As of December 31, 2024
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	23,816	$	—	$	23,816	$	(6,178)	$	17,638



Liabilities:
Current:
Derivative instruments	$	—	$	8,501	$	—	$	8,501	$	(6,178)	$	2,323
Non-current:

2026 WTI Contingent Liability	$	—	$	29,762	$	—	$	29,762	$	—	$	29,762


	As of December 31, 2023
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In thousands)
Assets:
Current:
Derivative instruments	$	—	$	7,040	$	—	$	7,040	$	(6,682)	$	358
Non-current:

Derivative instruments	$	—	$	1,269	$	—	$	1,269	$	(1,177)	$	92
Liabilities:
Current:
Derivative instruments	$	—	$	9,643	$	—	$	9,643	$	(6,682)	$	2,961
Non-current:
Derivative instruments	$	—	$	1,378	$	—	$	1,378	$	(1,177)	$	201

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, 2024				December 31, 2023
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Debt:
Revolving credit facility	$	261,000	$	261,000	$	263,000	$	263,000
5.375% senior notes due 2027(1)	$	427,049	$	424,110	$	425,949	$	422,122
7.375% senior notes due 2031(1)	$	394,930	$	420,108	$	394,133	$	418,408

(1) The carrying value includes associated deferred loan costs and any discount.

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

12 Months Ended

Dec. 31, 2024

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,
	2024		2023
	(In thousands)
Oil and natural gas interests:
Subject to depletion	$	3,532,834	$	2,859,642
Not subject to depletion	2,179,837		1,769,341
Gross oil and natural gas interests	5,712,671		4,628,983
Accumulated depletion and impairment	(1,080,764)		(866,352)
Oil and natural gas interests, net	4,631,907		3,762,631
Land	5,688		5,688
Property, net of accumulated depletion and impairment	$	4,637,595	$	3,768,319

Balance of costs not subject to depletion:
Incurred in 2024	$	798,705
Incurred in 2023	576,162
Incurred in 2022	33,053
Prior	771,917
Total not subject to depletion	$	2,179,837

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


	December 31,
	2024		2023
	(In thousands)
Oil and natural gas interests:
Proved	$	3,532,834	$	2,859,642
Unproved	2,179,837		1,769,341
Total oil and natural gas interests	5,712,671		4,628,983
Accumulated depletion and impairment	(1,080,764)		(866,352)
Net oil and natural gas interests capitalized	$	4,631,907	$	3,762,631

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,
	2024		2023		2022
	(In thousands)
Acquisition costs:
Proved properties	$	340,907	$	402,659	$	46,307
Unproved properties	830,450		758,342		16,624
Total	$	1,171,357	$	1,161,001	$	62,931

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, 2021	69,240	183,690	28,033	127,888
Purchase of reserves in place	599	1,186	209	1,006
Extensions and discoveries	15,714	29,177	5,281	25,858
Revisions of previous estimates	1,453	15,248	4,483	8,477
Divestitures	(905)	(3,469)	(564)	(2,047)
Production	(7,097)	(15,868)	(2,540)	(12,282)
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

Proved Developed Reserves:
December 31, 2022	54,817	161,119	25,621	107,291
December 31, 2023	69,043	221,462	37,417	143,371
December 31, 2024	76,020	253,271	45,633	163,865

Proved Undeveloped Reserves:
December 31, 2022	24,187	48,845	9,281	41,609
December 31, 2023	20,860	42,116	7,999	35,878
December 31, 2024	17,543	39,353	7,907	32,009

The following table includes the changes in PUD reserves for 2024:


			(MBOE)
Beginning proved undeveloped reserves at December 31, 2023			35,878
Undeveloped reserves transferred to developed			(16,696)
Revisions			(1,934)
Purchases			4,913

Extensions and discoveries			9,848
Ending proved undeveloped reserves at December 31, 2024			32,009

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, 2024, 2023 and 2022:


	December 31,
	2024		2023		2022
	(In thousands)
Future cash inflows	$	8,322,795	$	8,493,617	$	10,072,969
Future production taxes	(578,310)		(593,840)		(729,256)
Future income tax expense	(748,375)		(934,392)		(1,465,160)
Future net cash flows	6,996,110		6,965,385		7,878,553
10% discount to reflect timing of cash flows	(3,676,566)		(3,778,499)		(4,424,457)
Standardized measure of discounted future net cash flows(1)	$	3,319,544	$	3,186,886	$	3,454,096

(1) Includes a 43%, 51% and 55% non-controlling interest in the Company at December 31, 2024, 2023 and 2022, 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,
	2024		2023		2022


Oil (per Bbl)	$	75.61	$	77.93	$	95.04
Natural gas (per Mcf)	$	0.49	$	1.54	$	5.74
Natural gas liquids (per Bbl)	$	20.62	$	23.79	$	38.95

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,
	2024		2023		2022
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	3,186,886	$	3,454,096	$	2,093,117
Purchase of minerals in place	354,874		473,742		30,331
Divestiture of reserves	(51,119)		—		(30,076)
Sales of oil and natural gas, net of production costs	(792,694)		(666,709)		(781,604)
Extensions and discoveries	640,438		626,854		844,010
Net changes in prices and production costs	(438,456)		(1,405,205)		1,131,202
Revisions of previous quantity estimates	(84,949)		2,726		309,338
Net changes in income taxes	70,333		212,391		(393,652)
Accretion of discount	373,790		427,998		234,717
Net changes in timing of production and other	60,441		60,993		16,713
Standardized measure of discounted future net cash flows at the end of the period	$	3,319,544	$	3,186,886	$	3,454,096

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.