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Viper Energy, Inc. (VNOM)

CIK: 0002074176. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-25.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=2074176. Latest filing source: 0002074176-26-000010.

Selected Fundamentals

MetricValueUnitFYFiled
Revenue1,395,000,000USD20252026-02-25
Net income-68,000,000USD20252026-02-25
Assets12,671,000,000USD20252026-02-25

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-25. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0002074176.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Metric202320242025
Revenue828,000,000861,000,0001,395,000,000
Net income200,000,000359,000,000-68,000,000
Operating income620,000,000567,000,000-140,000,000
Diluted EPS2.693.82-0.48
Assets5,069,000,00012,671,000,000
Liabilities1,162,000,0002,308,000,000
Stockholders' equity1,687,000,0004,448,000,000
Cash and cash equivalents27,000,00013,000,000
Net margin24.15%41.70%-4.87%
Operating margin74.88%65.85%-10.04%

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-06. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0002074176.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

QuarterEnd DateRevenueNet IncomeDiluted EPSMethod
2025-Q32025-09-30418,000,000-77,000,000-0.52reported discrete quarter
2025-Q42025-12-31435,000,000-103,000,000derived Q4 = FY annual - nine-month YTD
2026-Q12026-03-31511,000,00097,000,0000.53reported discrete quarter

Quarterly Charts

Macro Cross-References

Latest quarter (10-Q)

Latest 10-Q source: 0002074176-26-000030.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-06. Report date: 2026-03-31.

ITEM 2.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2025. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Part II. Item 1A. Risk Factors, Part I. Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2025 and Cautionary Statement Regarding Forward-Looking Statements.

Overview

We are a publicly traded Delaware corporation focused on owning and acquiring mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin. We operate in one reportable segment.

Recent Developments

Pending Riverbend Acquisition

On May 1, 2026, we and Viper Energy Partners LP entered into a definitive purchase and sale agreement to acquire all of the equity interests of Riverbend Oil & Gas IX, L.L.C., from Riverbend for consideration consisting of (i) approximately $337 million in cash, and (ii) 3,689,865 shares of our Class A Common Stock, in each case, subject to customary closing adjustments. The mineral and royalty interests to be acquired in the Pending Riverbend Acquisition represent approximately 3,064 net royalty acres in the Permian Basin. The Pending Riverbend Acquisition is expected to close during the third quarter of 2026, subject to customary closing conditions. See Note 13—Subsequent Events of the notes to the condensed consolidated financial statements for additional information on the Pending Riverbend Acquisition.

Secondary Offering

On March 4, 2026, we completed the 2026 Secondary Offering, which authorized the Selling Stockholders to sell an aggregate of (i) 17,391,304 shares of Class A Common Stock, and (ii) up to an additional 2,608,696 shares of Class A Common Stock at the public offering price of $45.90. On March 19, 2026, the Underwriters exercised a portion of the Underwriter Option and purchased an additional 954,809 shares of Class A Common Stock. We did not receive any proceeds from the 2026 Secondary Offering or the Shoe Exercise.

Increase in Repurchase Program Authorization

On February 18, 2026, our board of directors approved an increase in authorization under our existing repurchase program from $750 million to $1.75 billion, excluding excise tax. As of May 1, 2026, approximately $1.14 billion remained available for future repurchases under our repurchase program, excluding excise tax.

Divestiture Update

Divestiture of Non-Permian Assets

On February 9, 2026, we completed the Non-Permian Divestiture for net cash proceeds of approximately $610 million, including transaction costs and customary post-closing adjustments. The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with then-current production of approximately 4,750 BO/d. Proceeds from the Non-Permian Divestiture were used to (i) repay the $500 million Term Loan in full, (ii) fully repay $90 million of then-outstanding borrowings under our Revolving Credit Facility, and (iii) for general corporate purposes.

At March 31, 2026, our footprint of mineral and royalty interests totaled approximately 86,639 net royalty acres, approximately 38% of which are operated by Diamondback. See Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for additional information on our acquisitions and divestitures.

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Commodity Prices

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Geopolitical global conflicts, tariffs or other trade barriers and any resulting trade tensions, regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, extreme weather conditions and other substantially variable factors influence market conditions for these products. For example, in the last quarter the global crude oil market shifted from a supply-demand surplus to a deficit, materially reducing crude oil and refined products from the markets, and increasing benchmark crude oil prices. These factors are beyond our control and are difficult to predict. OPEC+ continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels and can heavily influence volatility in oil prices. During the three months ended March 31, 2026, and 2025, WTI prices averaged $72.67 and $71.42 per Bbl, respectively, and Henry Hub prices averaged $3.47 and $3.87 per MMBtu, respectively.

Production and Operational Update

As of March 31, 2026, there were 88 gross rigs operating on our mineral and royalty acreage, 13 of which are operated by Diamondback. We delivered a strong start to 2026, with first quarter production exceeding expectations and an increased growth outlook for the remainder of 2026. With the Pending Riverbend Acquisition, we continue our strategy to consolidate the highly fragmented minerals and royalty sector. Currently, excluding the Pending Riverbend Acquisition, we estimate full year production levels in 2026 may range between approximately 126 MBOE/d to 130 MBOE/d.

The following table summarizes our gross well information for the first quarter ended March 31, 2026:

Diamondback Operated

Third-Party Operated

Total

Q1 2026 horizontal wells turned to production(1):

Gross wells

114

541

655

Net 100% royalty interest wells

8.6

6.7

15.3

Average percent net royalty interest

7.5 

%

1.2 

%

2.3 

%

Horizontal producing well count:

Gross wells

4,209

20,413

24,622

Net 100% royalty interest wells

267.2

317.2

584.4

Average percent net royalty interest

6.3 

%

1.6 

%

2.4 

%

Horizontal active development well count(2):

Gross wells

272

1,098

1,370

Net 100% royalty interest wells

20.3

17.1

37.4

Average percent net royalty interest

7.5 

%

1.6 

%

2.7 

%

Line of sight wells(3):

Gross wells

298

1,053

1,351

Net 100% royalty interest wells

13.6

15.4

29.0

Average percent net royalty interest

4.6 

%

1.5 

%

2.1 

%

(1)Average lateral length of 11,583 feet.

(2)The total 1,370 gross wells currently in the process of active development are those wells that have been spud and are expected to be turned to production within approximately the next six to eight months.

(3)The total 1,351 gross line-of-sight wells are those that are not currently in the process of active development, but for which we have reason to believe will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third-party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices.

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Results of Operations

Comparison of the Three Months Ended March 31, 2026, and December 31, 2025

The following table summarizes our income and expenses for the periods indicated:

Three Months Ended

March 31, 2026

December 31, 2025

(In millions)

Operating income:

Oil income

$

428 

$

357 

Natural gas income

16 

16 

Natural gas liquids income

52 

49 

Royalty income

496 

422 

Lease bonus income

14 

5 

Lease bonus income—related party

1 

7 

Other operating income

— 

1 

Total operating income

511 

435 

Costs and expenses:

Production and ad valorem taxes

35 

29 

Depletion

206 

234 

Impairment

— 

408 

General and administrative expenses

8 

6 

General and administrative expenses—related party

5 

6 

Other operating expenses

4 

6 

Total costs and expenses

258 

689 

Income (loss) from operations

253 

(254)

Other income (expense):

Interest expense, net

(27)

(36)

Gain (loss) on derivative instruments, net

18 

23 

Gain (loss) on early extinguishment of debt

(1)

— 

Total other income (expense), net

(10)

(13)

Income (loss) before income taxes

243 

(267)

Provision for (benefit from) income taxes

28 

(21)

Net income (loss)

215 

(246)

Net income (loss) attributable to non-controlling interest

118 

(143)

Net income (loss) attributable to Viper Energy, Inc.

$

97 

$

(103)

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The following table summarizes our production data, average sales prices and average costs for the periods indicated:

Three Months Ended

March 31, 2026

December 31, 2025

Production data:

Oil (MBbls)

5,850 

6,110 

Natural gas (MMcf)

18,088 

19,668 

Natural gas liquids (MBbls)

2,899 

2,940 

Combined volumes (MBOE)(1)

11,764 

12,328 

Average daily oil volumes (BO/d)

65,000 

66,413 

Average daily combined volumes (BOE/d)

130,711 

134,000 

Average sales price:

Oil ($/Bbl)

$

73.16 

$

58.43 

Natural gas ($/Mcf)

$

0.88 

$

0.81 

Natural gas liquids ($/Bbl)

$

17.94 

$

16.67 

Combined ($/BOE)(2)

$

42.16 

$

34.23 

Oil, hedged ($/Bbl)(3)

$

72.31 

$

57.28 

Natural gas, hedged ($/Mcf)(3)

$

2.27 

$

1.53 

Natural gas liquids ($/Bbl)(3)

$

17.94 

$

16.67 

Combined price, hedged ($/BOE)(3)

$

43.86 

$

34.80 

Average costs ($/BOE):

Production and ad valorem taxes

$

2.98 

$

2.35 

General and administrative - cash component

0.94 

0.81 

Total operating expense - cash

$

3.92 

$

3.16 

General and administrative - non-cash stock compensation expense

$

0.17 

$

0.16 

Interest expense, net

$

2.30 

$

2.92 

Depletion

$

17.51 

$

18.98 

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2)Realized price net of all deducts for gathering, transportation and processing.

(3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices.

Significant changes in our revenues and expenses between the first quarter of 2026 and the fourth quarter of 2025 are discussed further below.

Royalty Income. Our royalty income is a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes.

Royalty income increased by $74 million during the first quarter of 2026 compared to the fourth quarter of 2025. This net increase consisted of an additional $91 million in royalty income attributable to higher average commodity prices received primarily for our oil production in the first quarter of 2026 compared to the fourth quarter of 2025, partially offset by a reduction of $17 million due to a 5% decrease in our production.

Of the 5% decrease in production, approximately 3% was attributable to the Non-Permian Divestiture, with the remaining change largely due to having two fewer days in the first quarter of 2026 compared to the fourth quarter of 2025. See

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Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for additional discussion of our acquisitions.

Production and Ad Valorem Taxes. The following table presents production and ad valorem taxes for the periods indicated:

Three Months Ended

March 31, 2026

December 31, 2025

Amount

(In millions)

Per BOE

Percentage of Royalty Income

Amount

(In millions)

Per BOE

Percentage of Royalty Income

Production taxes

$

26 

$

2.21 

5.3 

%

$

23 

$

1.86 

5.5 

%

Ad valorem taxes

9 

0.77 

1.8 

6 

0.49 

1.4 

Total production and ad valorem taxes

$

35 

$

2.98 

7.1 

%

$

29 

$

2.35 

6.9 

%

In

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-25. Report date: 2025-12-31.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto presented in Item 8. Financial Statements and Supplementary Data of this report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors discussed further in Item 1A. Risk Factors and Cautionary Statement Regarding Forward-Looking Statements of this report.

Overview

We are a publicly traded Delaware corporation focused on owning and acquiring mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin. We operate in one reportable segment.

The following discussion includes a comparison of our results of operations, including changes in our operating income, and liquidity and capital resources for fiscal year 2025 and fiscal year 2024. A discussion of changes in our results of operations from fiscal year 2024 compared to fiscal year 2023 has been omitted from this report, but may be found in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 26, 2025, and is incorporated by reference in this report from such prior Annual Report on Form 10-K.

Recent Developments

2026 Activity

Increase in Repurchase Program Authorization

On February 18, 2026, our board of directors approved an increase in authorization under our existing repurchase program from $750 million to $1.75 billion, excluding excise tax. As of February 20, 2026, approximately $1.2 billion remains available for future repurchases under our repurchase program, excluding excise tax.

Cash Dividends

On February 18, 2026, our board of directors approved (i) an increase to our annual base dividend to $1.52 per share of Class A Common Stock beginning with the dividend payable for the fourth quarter of 2025, and (ii) a combined quarterly base and variable cash dividend of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit payable on March 12, 2026.

Divestiture of Non-Permian Assets

On February 9, 2026, we completed the Non-Permian Divestiture for net cash proceeds of approximately $617 million, subject to customary post-closing adjustments. The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d. Proceeds from the Non-Permian Divestiture were used to repay the Term Loan (as defined below) and to reduce borrowings outstanding on the 2025 Revolving Credit Facility (as defined below).

2025 Activity

Acquisitions Update

Sitio Acquisition

On August 19, 2025, we completed the Sitio Acquisition in an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres.

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2025 Drop Down

On May 1, 2025, we completed the 2025 Drop Down for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69,626,640 OpCo Units and an equivalent number of shares of our Class B Common Stock (collectively, the “Drop Down Equity Issuance”). The mineral and royalty interests acquired in the 2025 Drop Down represent approximately 24,446 net royalty acres in the Permian Basin, 69% of which are operated by Diamondback.

Other Acquisitions

During the year ended December 31, 2025, we acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 515 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $140 million, including customary closing adjustments. Additionally, during the year ended December 31, 2025, we acquired from Morita Ranches Minerals, LLC, mineral and royalty interests representing 1,691 net royalty acres in the Permian Basin for consideration consisting of $208 million in cash and 2,400,297 OpCo Units together with an equal number of shares of our Class B Common Stock, including customary transaction costs and post-closing adjustments.

At December 31, 2025, our footprint of mineral and royalty interests totaled approximately 96,003 net royalty acres, approximately 35% of which are operated by Diamondback.

See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further information.

Debt Transactions

Notes Offering and Retirement of Notes

On July 23, 2025, the Operating Company issued the Guaranteed Senior Notes for an aggregate principal amount of $1.6 billion. Using approximately $824 million of the net proceeds from the issuance of the Guaranteed Senior Notes, we redeemed all of our 7.375% Senior Notes maturing on November 1, 2031 (the “2031 Notes”) and on November 1, 2025 we redeemed our 5.375% Senior Notes due 2027 (the “2027 Notes”), including accrued and unpaid interest through the date of redemption and any redemption premiums. We used the remaining net proceeds to partially retire Sitio’s net debt of approximately $1.2 billion including any fees, costs and expenses related to the redemption or repayment of such debt, and for general corporate purposes.

Additionally, in the second quarter of 2025, prior to redemption, we opportunistically repurchased principal amounts of $50 million of the 2027 Notes in open market transactions for total cash consideration of $50 million, at an average of 99.7% of par value.

On December 23, 2025, Old OpCo converted its legal form (the “OpCo Conversion”), in accordance with the applicable laws of the State of Delaware, to a Delaware limited partnership named Viper Energy Partners LP (“Viper LP”), which is now the issuer with respect to the Guaranteed Senior Notes.

Term Loan

On July 23, 2025, Former Viper, as guarantor, the Operating Company, as borrower, and Goldman Sachs Bank USA, as administrative agent, entered into a $500 million term loan credit agreement (the “Term Loan”), which was fully drawn to partially fund the retirement of Sitio’s net debt. Following the closing of the Sitio Acquisition, New Viper became an additional guarantor of the borrower’s obligations under the Term Loan. Following the OpCo Conversion, Viper LP became the borrower under the Term Loan.

2025 Revolving Credit Facility

On June 12, 2025, Former Viper, as guarantor, entered into a credit agreement with the Operating Company, as borrower, and Wells Fargo, as the administrative agent providing for a senior unsecured revolving credit facility with a commitment amount of $1.5 billion (the “2025 Revolving Credit Facility”). The 2025 Revolving Credit Facility was previously guaranteed by certain subsidiaries of the Operating Company, and upon completion of the Sitio Acquisition, those subsidiary guarantees were released and New Viper and Former Viper became co-guarantors. The 2025 Revolving Credit Facility replaced

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the borrower’s previous revolving credit facility, and will mature on June 12, 2030, unless extended in accordance with its terms. Following the OpCo Conversion, Viper LP became the borrower under the 2025 Revolving Credit Facility.

See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our debt.

2025 Equity Offering

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

Commodity Prices and Certain Other Market Considerations

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, tariffs or other trade barriers and any resulting trade tensions, regional conflicts and political instability, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. OPEC+ continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels and can heavily influence volatility in oil prices. During 2025, 2024 and 2023, WTI prices averaged $64.73, $75.76 and $77.60 per Bbl, respectively, and Henry Hub prices averaged $3.62, $2.41 and $2.66 per MMBtu, respectively. For additional information around risks related to commodity prices, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.

Based on 2025 commodity prices, industry conditions and the results of the quarterly ceiling tests, we were required to record aggregate non-cash impairments of $768 million on our proved oil and natural gas interests during the year ended December 31, 2025. If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows may be adversely impacted. Our business may also be adversely impacted by any pipeline capacity and storage constraints.

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Production and Operational Update

As of December 31, 2025, there were 98 gross rigs operating on our mineral and royalty acreage, eight of which are operated by Diamondback. During 2025, we completed the Sitio Acquisition and the 2025 Drop Down, which reinforced the durability of our growth outlook and leveraged our leading position in the minerals and royalty sector to advance our differentiated acquisition strategy. Currently, we estimate full year production levels in 2026 to range between approximately 120 MBOE/d to 132 MBOE/d.

The following table summarizes our gross well information excluding the recently divested non-Permian assets as of December 31, 2025, unless otherwise specified:

Diamondback Operated

Third-Party Operated

Total

Horizontal wells turned to production (fourth quarter 2025)(1):

Gross wells

107

632

739

Net 100% royalty interest wells

5.3

7.7

13.0

Average percent net royalty interest

5.0 

%

1.2 

%

1.8 

%

Horizontal wells turned to production (year ended December 31, 2025)(2):

Gross wells

415

1,670

2,085

Net 100% royalty interest wells

20.7

21.3

42.0

Average percent net royalty interest

5.0 

%

1.3 

%

2.0 

%

Horizontal producing well count:

Gross wells

4,092

19,942

24,034

Net 100% royalty interest wells

258.3

311.1

569.4

Average percent net royalty interest

6.3 

%

1.6 

%

2.4 

%

Horizontal active development well count(3):

Gross wells

263

1,125

1,388

Net 100% royalty interest wells

20.9

17.3

38.2

Average percent net royalty interest

7.9 

%

1.5 

%

2.8 

%

Line of sight wells(4):

Gross wells

304

1,066

1,370

Net 100% royalty interest wells

16.9

15.1

32.0

Average percent net royalty interest

5.6 

%

1.4 

%

2.3 

%

(1)Average lateral length of 11,283 feet.

(2)Average lateral length of 11,618 feet.

(3)The total 1,388 gross wells currently in the process of active development are those wells that have been spud and are expected to be turned to production within approximately the next six to eight months.

(4)The total 1,370 line-of-sight wells are those that are not currently in the process of active development, but for which we have reason to believe will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third-party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our net royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices.

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Results of Operations

The following table summarizes our income and expenses for the periods indicated:

Year Ended December 31,

2025

2024

(In millions)

Operating income:

Oil income

$

1,131 

$

750 

Natural gas income

56 

15 

Natural gas liquids income

159 

89 

Royalty income

1,346 

854 

Lease bonus income

24 

6 

Lease bonus income—related party

24 

— 

Other operating income

1 

1 

Total operating income

1,395 

861 

Costs and expenses:

Production and ad valorem taxes

94 

61 

Depletion

607 

214 

Impairment

768 

— 

General and administrative expenses

18 

8 

General and administrative expenses—related party

17 

11 

Other operating expenses

31 

— 

Total costs and expenses

1,535 

294 

Income (loss) from operations

(140)

567 

Other income (expense):

Interest expense, net

(96)

(74)

Gain (loss) on derivative instruments, net

44 

11 

Gain (loss) on early extinguishment of debt

(32)

— 

Other income (expense), net

(1)

— 

Total other income (expense), net

(85)

(63)

Income (loss) before income taxes

(225)

504 

Provision for (benefit from) income taxes

(19)

(100)

Net income (loss)

(206)

604 

Net income (loss) attributable to non-controlling interest

(138)

245 

Net income (loss) attributable to Viper Energy, Inc.

$

(68)

$

359 

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The following table summarizes our production data, average sales prices and average costs for the periods indicated:

Year Ended December 31,

2025

2024

Production data:

Oil (MBbls)

17,875 

9,939 

Natural gas (MMcf)

51,676 

24,606 

Natural gas liquids (MBbls)

8,233 

4,181 

Combined volumes (MBOE)(1)

34,721 

18,221 

Average daily oil volumes (BO/d)

48,973 

27,156 

Average daily combined volumes (BOE/d)

95,126 

49,784 

Average sales prices:

Oil ($/Bbl)

$

63.27 

$

75.48 

Natural gas ($/Mcf)

$

1.08 

$

0.60 

Natural gas liquids ($/Bbl)

$

19.31 

$

21.17 

Combined ($/BOE)(2)

$

38.77 

$

46.85 

Oil, hedged ($/Bbl)(3)

$

62.38 

$

74.57 

Natural gas, hedged ($/Mcf)(3)

$

1.92 

$

0.85 

Natural gas liquids ($/Bbl)(3)

$

19.31 

$

21.17 

Combined price, hedged ($/BOE)(3)

$

39.54 

$

46.68 

Average costs ($/BOE):

Production and ad valorem taxes

$

2.71 

$

3.34 

General and administrative - cash component

0.81 

0.86 

Total operating expense - cash

$

3.52 

$

4.20 

General and administrative - non-cash stock compensation expense

$

0.20 

$

0.16 

Interest expense, net

$

2.76 

$

4.05 

Depletion

$

17.48 

$

11.77 

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2)Realized price net of all deducts for gathering, transportation and processing.

(3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices.

Significant changes in our revenues and expenses for 2025 compared to the same period in 2024 are discussed below.

Royalty Income. Our royalty income is a function of oil, natural gas and natural gas liquids production volumes sold and average prices received for those volumes.

Royalty income increased $492 million in 2025 compared to the same period in 2024. This net increase consisted of an additional $701 million in royalty income from the 91% growth in production, partially offset by a net decrease of $209 million due primarily to lower average prices received for our oil and natural gas liquids production during 2025 compared to the same period in 2024.

Of the 91% growth in production, approximately 46% is attributable to the 2025 Drop Down and 32% is attributable to the Sitio Acquisition. The remainder of the growth is primarily from new wells added between periods and other individually insignificant acquisitions. See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our acquisitions.

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Production and Ad Valorem Taxes. The following table presents production and ad valorem taxes for the periods indicated:

Year Ended December 31,

2025

2024

Amount

(In millions)

Per BOE

Percentage of Royalty Income

Amount

(In millions)

Per BOE

Percentage of Royalty Income

Production taxes

$

69 

$

1.99 

5.1 

%

$

43 

$

2.33 

5.0 

%

Ad valorem taxes

25 

0.72 

1.9 

18 

1.01 

2.1 

Total production and ad valorem taxes

$

94 

$

2.71 

7.0 

%

$

61 

$

3.34 

7.1 

%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Production taxes and ad valorem taxes as a percentage of royalty income in 2025 were relatively consistent with the same period in 2024.

Depletion. The increase in depletion expense of $393 million in 2025 compared to the same period in 2024 consisted primarily of (i) $198 million due to an increase in the depletion rate to $17.48 per BOE in 2025, resulting primarily from the addition of leasehold costs and reserves from acquisitions completed in 2025, compared to $11.77 per BOE for the same period in 2024, and (ii) $195 million from growth in production volumes.

Impairment. In 2025, we recorded non-cash ceiling test impairment charges of $768 million due to the carrying value of our proved reserves exceeding their estimated future net cash flows utilizing the SEC’s methodology and pricing at December 31, 2025. The excess value resulted primarily from recording properties acquired in the 2025 Drop Down at Diamondback’s historical carrying value, which exceeded the value calculated in the third and fourth quarter 2025 ceiling tests, due primarily to declining SEC Prices. No impairment expense was recorded in 2024.

Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Given the overall decline in SEC Prices from the first quarter of 2025 through the first two months of 2026, we believe an additional material non-cash impairment of our assets is reasonably likely to occur in the first quarter of 2026; however, based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine an estimate of the amount or range of amounts of any potential impairment charge in the first quarter of 2026.

General and Administrative Expenses. The following table shows a breakout of our general and administrative expenses for the periods presented:

Year Ended December 31,

2025

2024

(In millions, except per BOE amounts in ones)

General and administrative expenses

$

18 

$

8 

General and administrative expenses—related party

17 

11 

General and administrative expenses

$

35 

$

19 

General and administrative expenses (per BOE)

$

1.01 

$

1.02 

Interest Expense, Net. The increase in net interest expense of $22 million in 2025 compared to the same period in 2024 consisted primarily of (i) $40 million in additional expense on our Guaranteed Senior Notes, which were issued July 23, 2025, (ii) $11 million in additional interest expense incurred on the Term Loan, and (iii) other individually insignificant changes. These increases in net interest expense were partially offset by (i) interest cost savings of approximately $16 million due to the early termination of the Notes, (ii) $8 million in additional interest income, and (iii) a decrease of approximately $5

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million in interest expense on our current and previous revolving credit facility due to lower average borrowings outstanding in 2025.

Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:

Year Ended December 31,

2025

2024

(In millions)

Gain (loss) on derivative instruments, net

$

44 

$

11 

Net cash receipts (payments) on derivatives

$

30 

$

(3)

The $33 million increase in the gain on derivative instruments, net in 2025 compared to the same period in 2024 consists primarily of (i) an $11 million net gain on our natural gas contracts, which consists of a $30 million net increase in cash receipts on our settled natural gas basis swaps, partially offset by a $19 million decrease in the value of our open natural gas contracts primarily due to changes in the differential between prices for Waha Hub and Henry Hub, (ii) a $13 million decrease in the estimated fair value of our 2026 WTI Contingent Liability based on fluctuations in the final WTI 2025 Average price (each as defined in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report), and (iii) other individually insignificant changes. See Note 10—Derivatives in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our open contracts at December 31, 2025.

Gain (Loss) on Early Extinguishment of Debt. The $32 million loss on early extinguishment of debt in 2025 is due to the retirement of the 2031 Notes. See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our debt at December 31, 2025.

Provision for (Benefit from) Income Taxes. The $81 million decrease in income tax benefit in 2025 compared to the same period in 2024 primarily resulted from recognizing a pre-tax loss attributable to Viper in 2025 compared to pre-tax income attributable to Viper in 2024, driven by the $768 million non-cash ceiling test impairments recorded in 2025. Additionally, the income tax benefit recognized in 2024 reflects the full release of a valuation allowance of $156 million during the fourth quarter of 2024. See Note 9—Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of income tax expense.

Net Income (Loss) Attributable to Non-Controlling Interest. The change to $138 million in net loss attributable to non-controlling interest in 2025 from $245 million in net income attributable to non-controlling interest in 2024 is primarily due to the non-cash ceiling test impairments recorded in 2025 and changes in the non-controlling interest in the Operating Company resulting from (i) the Drop Down Equity Issuance, (ii) the issuance of OpCo Units to fund the Sitio Acquisition, and (iii) the issuance of OpCo Units to Tumbleweed Royalty IV, LLC in the fourth quarter of 2024, which were partially offset by a dilution of the non-controlling interest following the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report) and the 2025 Equity Offering.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations and liquidity requirements. Our future ability to grow proved reserves will be highly dependent on the capital resources available to us. Our primary sources of liquidity have been cash flow from operations, equity and debt offerings, borrowings under our revolving credit facility, term loan agreement and proceeds from sales of non-core assets. Our primary uses of cash have been dividends to our stockholders, Operating Company distributions to the holders of OpCo Units, repayments of debt, capital expenditures for the acquisition of our mineral and royalty interests in oil and natural gas properties, including the recently completed Sitio Acquisition, the 2025 Drop Down, and various individually insignificant acquisitions and repurchases of our Common Stock and OpCo Units. At December 31, 2025, we had approximately $1.4 billion of liquidity consisting of $13 million in cash and cash equivalents and $1.4 billion in available borrowings under the 2025 Revolving Credit Facility. See further discussion of changes in our sources of cash in “—Capital Resources” below.

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Our working capital requirements are supported by our cash and cash equivalents and the 2025 Revolving Credit Facility. We may draw on the 2025 Revolving Credit Facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including dividends, debt service obligations, repayment of debt maturities, any repurchases of our Common Stock, OpCo Units or Guaranteed Senior Notes and any amounts that may ultimately be paid in connection with contingencies.

In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts as discussed further in Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of this report.

Continued prolonged volatility in the capital, financial and/or credit markets due to changing or adverse macroeconomic conditions, including tariffs, higher interest rates, global supply chain disruptions, actions taken by OPEC members and other exporting nations and geopolitical global conflicts may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although we expect that our sources of funding will be adequate to fund our short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.

Cash Flows

The following table presents our cash flows for the period indicated:

Year Ended December 31,

2025

2024

(In millions)

Net cash provided by (used in) operating activities

$

1,053 

$

620 

Net cash provided by (used in) investing activities

(2,424)

(608)

Net cash provided by (used in) financing activities

1,357 

(11)

Net increase (decrease) in cash and cash equivalents

$

(14)

$

1 

Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volumes of oil and natural gas sold by our operators. The increase in net cash provided by operating activities in 2025, compared to the same period in 2024 was primarily driven by an increase in royalty and lease bonus income and receiving cash payments on our derivatives in 2025 compared to making cash payments to counterparties in 2024. These increases in cash flow were partially offset by an increase in certain cash costs for production and ad valorem taxes, general and administrative expenses, other operating expenses which include severance costs related to the Sitio Acquisition and other changes in our working capital accounts including the timing of when accounts receivable are collected and accounts payable are remitted. See “—Results of Operations” above for further discussion of significant changes in our income and expenses.

Investing Activities

Net cash used in investing activities during the year ended December 31, 2025, was primarily related to acquisitions of oil and natural gas interests, including the approximately $1.2 billion repayment made for Sitio’s outstanding debt as part of the consideration for the Sitio Acquisition, the 2025 Drop Down, and acquisitions of oil and natural gas interests from other third parties. See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for additional information on these acquisitions.

Net cash used in investing activities during the year ended December 31, 2024, primarily related to acquisitions of oil and natural gas interests from third parties, which includes $654 million in cash paid for the Tumbleweed Acquisitions (as defined and discussed in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report), partially offset by proceeds of $88 million primarily from the divestiture of non-Permian oil and natural gas interests.

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Financing Activities

Net cash provided by financing activities during the year ended December 31, 2025, was primarily attributable to (i) net proceeds from the issuance of the Guaranteed Senior Notes of $1.6 billion, (ii) proceeds of $1.2 billion from the 2025 Equity Offering, and (iii) net proceeds from the Term Loan of $500 million. These cash inflows were partially offset by (i) $745 million of dividends paid to holders of our OpCo Units and our Class A Common Stock, (ii) $430 million paid for the retirement of the outstanding principal on our 2027 Notes, (iii) $427 million paid for the retirement of the outstanding principal and the redemption premium on our 2031 Notes, (iv) $194 million of securities repurchases under the Company’s repurchase program, and (v) repayments net of borrowings of $156 million on the 2025 Revolving Credit Facility.

Net cash used in financing activities during the year ended December 31, 2024, was primarily attributable to $481 million of dividends paid to stockholders and the Operating Company’s unitholders, which was largely offset by proceeds of $476 million from the 2024 Equity Offering (as defined and discussed in Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report).

Capital Resources

The 2025 Revolving Credit Facility and Other Debt Instruments

At December 31, 2025, our credit facility, which matures on June 12, 2030, had a commitment amount of $1.5 billion, with $105 million in outstanding borrowings and $1.4 billion of availability. In the first quarter of 2026, we fully repaid the $105 million of outstanding borrowings under our credit facility.

Additionally, at December 31, 2025, we had $500 million in outstanding borrowings under the Term Loan, which we subsequently repaid in full with proceeds from the Non-Permian Divestiture in February 2026.

See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our outstanding debt at December 31, 2025.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S., which impact the interest rates we receive on our variable rate debt and interest rate swaps. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. In May 2025, Fitch Investor Services upgraded our credit rating to investment grade, the second such investment grade credit rating for us. This upgrade granted us access to a broader investor base, lower interest rates and reduced collateral requirements; therefore, enhancing our liquidity. Currently, our credit ratings from the three main credit rating agencies are as follows:

•Standard and Poor’s Global Ratings Services (BBB-);

•Fitch Investor Services (BBB-); and

•Moody’s Investor Services (Ba1).

Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Capital Requirements

Guaranteed Senior Notes

At December 31, 2025, we had total principal payments due on our outstanding Guaranteed Senior Notes of $500 million in 2030 and $1.1 billion in 2035. Additionally, we have a remaining aggregate interest expense obligation of $750 million on the Guaranteed Senior Notes with $87 million due in 2026, an aggregate of $174 million due for years 2027 to 2028, an aggregate of $174 million due for years 2029 to 2030, and $315 million due thereafter. The Guaranteed Senior Notes are not subject to any mandatory redemption or sinking fund requirements. See Note 6—Debt in Item 8. Financial Statements and Supplementary Data of this report for further information on the Notes.

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Repurchases of Securities

On December 10, 2025, our board of directors expanded our repurchase program to include repurchases of our Class B Common Stock and OpCo Units in addition to our previously authorized Class A Common Stock. On February 18, 2026, our board of directors also approved an increase in our repurchase program authorization from $750 million to $1.75 billion, excluding the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the IRA. Since the inception of our repurchase program through February 20, 2026, we have repurchased an aggregate of 18,878,469 shares of our Common Stock and OpCo Units for a total cost of $525 million, excluding any applicable excise tax, leaving approximately $1.2 billion for future repurchases under the repurchase program. See Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program.

Cash Dividends and Return of Capital Update

We paid a total of $745 million and $481 million in dividends, on our Class A Common Stock, OpCo Units and participating securities under the LTIP during 2025 and 2024, respectively.

Because of our high operating and free cash flow margin, strong balance sheet, and the Non-Permian Divestiture closure, we returned 90% of cash available for distribution to stockholders with respect to the fourth quarter of 2025. As a result, in addition to repurchases under our repurchase program, we will pay a cash dividend for the fourth quarter of 2025 of $0.52 per share of Class A Common Stock and $0.65 per OpCo Unit, in each case payable on March 12, 2026, to eligible holders of record at the close of business on March 5, 2026. The dividend to stockholders consists of a base quarterly dividend of $0.38 per share of Class A Common Stock and a variable quarterly dividend of $0.14 per share of Class A Common Stock.

We moved closer to our net debt target of $1.5 billion following the closure of the Non-Permian Divestiture on February 9, 2026, and are positioned to increase our return of capital upwards of 100% of future cash available for distribution to stockholders, while also delivering sustainable per-share growth.

See Note 7—Stockholders’ Equity in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program and dividends. We expect to continue paying quarterly cash dividends in respect of our common shares. Future base and variable dividends are not required and are at the discretion of the board of directors, who may change the dividend policies at any time.

Supplemental Guarantor Disclosure

On July 9, 2025, New Viper, Former Viper and the Operating Company filed a registration statement on Form S-3 with the SEC registering debt securities of the Operating Company. On July 23, 2025, the Operating Company issued the Guaranteed Senior Notes for an aggregate principal amount of $1.6 billion, which are fully and unconditionally guaranteed by each of Former Viper and New Viper. Following the OpCo Conversion, Viper LP became the issuer of the Guaranteed Senior Notes.

The Guaranteed Senior Notes and the guarantees are the issuer’s and each guarantor’s respective senior unsecured obligations and rank equally in right of payment with all of the issuer’s and each guarantor’s respective existing and future senior indebtedness, including all of the issuer’s and each guarantor’s obligations under the 2025 Revolving Credit Facility and the New Loan, and senior in right of payment to any of the issuer’s and each guarantor’s future indebtedness that is expressly subordinated in right of payment to the Guaranteed Senior Notes and the guarantees, respectively.

The Guaranteed Senior Notes and the guarantees are effectively subordinated to any of the issuer’s and each guarantor’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and are structurally subordinated to all of the existing and future indebtedness and other liabilities (including trade payables) of each of the issuer’s and each guarantor’s respective subsidiaries that is not an obligor on the Guaranteed Senior Notes.

In the event of bankruptcy, liquidation, reorganization or other winding up of the issuer or a guarantor or upon a default in payment with respect to, or the acceleration of, any senior secured indebtedness of the issuer or a guarantor, the assets of the issuer or such guarantor that secure such senior secured indebtedness will be available to pay obligations on the Guaranteed Senior Notes and the guarantees only after all obligations under such senior secured indebtedness have been repaid in full from such assets. There may not be sufficient assets remaining to pay amounts due on any or all of the Guaranteed Senior Notes then outstanding and the guarantees.

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The obligations of the guarantors under the guarantees are limited in a manner designed to prevent the guarantees from constituting a fraudulent conveyance or fraudulent transfer under applicable law, although no assurance can be given that a court would give the holder the benefit of such provision. If a guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including contingent liabilities) of such guarantor, and, depending on the amount of such indebtedness, the guarantor’s liability on such guarantee could be reduced to zero.

In accordance with Rule 3-10 of Regulation S-X, subsidiary issuers of obligations guaranteed by the parent are not required to provide separate financial statements, provided that the subsidiary obligor is consolidated into the parent company’s consolidated financial statements, the parent guarantee is “full and unconditional,” except that such guarantee will be released or terminated in certain circumstances set forth in the indentures governing the Guaranteed Senior Notes, and, subject to certain exceptions, the alternative disclosures specified in Rule 13-01 are provided, which include narrative disclosure and summarized financial information. Accordingly, separate consolidated financial statements of the issuer have not been presented. Furthermore, as permitted under Rule 13-01(a)(4)(vi) of Regulation S-X, we have excluded the summarized financial information for the issuer because the assets, liabilities and results of operations of the issuer are not materially different than the corresponding amounts in our consolidated financial statements and management believes such summarized financial information would be repetitive and would not provide incremental value to investors.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Accounting estimates are considered to be critical if (i) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (ii) the impact of the estimates and assumptions on financial condition or operating performance is material. We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Any effects on our 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.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

Royalty Income and Revenue Recognition

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and natural gas liquids sales from third-party operators other than Diamondback may not be received for 30 to 90 days after the date production is delivered. 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 based upon our royalty interest. Where available, historical actual data is used to calculate volume estimates for wells operated by third parties. If historical actual data is not available for these wells, engineering estimates are used to calculate expected volumes. As such, estimated volumes utilized in period end royalty income accruals are subject to revision as additional actual data becomes available and such revisions may have a material impact on our results of operations and our royalty income receivables. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis. We record the differences between our estimates and the actual amounts received for royalties from third parties in the month that payment is received from the operator. We have existing internal controls for our royalty income estimation process and related accruals, but actual third-party royalty income in future periods could differ materially from estimated amounts. At December 31, 2025, our accrual for third-party royalty income was approximately $95 million. Actual revenues received during 2025 for prior years’ production from third parties were not materially different than the amount accrued at December 31, 2024.

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Oil and Natural Gas Accounting and Reserves

We account for oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. Further, we utilize estimated proved reserves to assign fair value to acquired mineral and royalty interests. As such, we consider the estimation of proved reserves to be a critical accounting estimate.

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. 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, independent petroleum engineers, as of December 31, 2025, 2024 and 2023. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include anticipated production of proved reserves and other relevant data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future depletion of capitalized costs and result in impairment of assets that may be material. Aggregate non-cash ceiling test impairments of $768 million were recorded on our proved oil and natural gas properties during the year ended December 31, 2025. No impairments were recorded on our proved oil and natural gas properties during the years ended December 31, 2024 and 2023. Based on SEC Prices for oil and natural gas throughout 2025 and into 2026, we believe an additional impairment is reasonably likely to occur in the first quarter of 2026. Any future impairment could be material to our consolidated financial statements.

Additionally, costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property (on an individual basis or as a group if properties are individually insignificant) at least annually for possible impairment. This assessment is subjective and includes consideration of the following factors, among others: (i) monitoring information available from third-party operators of our acreage for future drilling plans, (ii) the success of operators drilling on our acreage, (iii) the assignment of proved reserves, and (iv) current market prices for mineral acreage within our primary basins. At December 31, 2025, our unevaluated properties totaled $4.9 billion. We did not record any impairment on our unevaluated properties during the year ended December 31, 2025, but any such future impairment could be material to our consolidated financial statements.

Acquisitions of Mineral and Royalty Interests

Acquisitions of mineral and royalty interests from third parties are accounted for as asset acquisitions, whereby the purchase price and associated transaction costs are typically capitalized and allocated to the acquired mineral and royalty interests. The allocation is determined based on whether the interests acquired relate to proved or unproved oil and natural gas properties, utilizing the estimated fair value of proved reserves as of the date of acquisition. The valuation of proved reserves for acquisitions from unrelated parties is based on a projection of future cash flows using objective future pricing assumptions and a discount rate consistent with our estimated cost of capital at the time of the acquisition.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We use 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 after considering all positive and negative evidence available concerning the realizability of our deferred tax assets. Positive evidence may include forecasts of future taxable income, assessment of future business assumptions and any applicable tax planning strategies available to us. Negative evidence may include losses in recent years, if any, or the projection of losses in future periods. Estimating future taxable income requires numerous judgments and

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assumptions, including projections of future operating conditions which may be impacted by volatile future prices for our oil, natural gas and natural gas liquids, the expected timing and quantity of future production volumes, and the impact of our commodity derivative instruments on our income. These assumptions are discussed further in the critical accounting estimates titled “— Royalty Income and Revenue Recognition” and “— Oil and Natural Gas Accounting and Reserves.” Due to the impact these various assumptions and estimates can have on our estimates of taxable income, an estimate of the sensitivity to changes is not practicable.

In 2025, management’s assessment of all available evidence, both positive and negative, supporting realizability of our deferred tax assets as required by applicable accounting standards, supported the conclusion that our deferred tax assets are more likely than not to be realized. A variety of positive evidence was assessed. In recent years, we have sustained cumulative pre-tax income due in part to higher commodity prices resulting from strong and stable market conditions, and the locations in which we operate have experienced a sustained and increasing pattern of development by a wide variety of operators, consistent with a presumption of more readily predictable development patterns for our properties. The significant acquisitions completed by us, including the Sitio Acquisition and the 2025 Drop Down, provide additional production capacity to generate future taxable income for utilization of our deferred tax assets. In addition, the recently closed Non-Permian Divestiture provides positive evidence supporting realizability of our capital loss carryforward against the estimated capital gain to be recognized in 2026. Based on these factors, we determined that no valuation allowance on our deferred tax assets is required as of December 31, 2025. As of December 31, 2025, we had net deferred tax assets of $33 million.

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for discussion of recent accounting pronouncements and a full listing of our significant accounting policies.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.