Diamondback Energy, Inc. (FANG)

CIK: 0001539838. 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=1539838. Latest filing source: 0001539838-26-000010.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-25. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001539838.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.

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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 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 an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. As of December 31, 2025, we have one reportable segment, the upstream segment. See Note 1—Description of the Business and Basis of Presentation and Note 17—Segment Information in Item 8. Financial Statements and Supplementary Data of this report for further discussion.

2025 Financial and Operating Highlights

•Recorded net income of $1.7 billion, which includes impairment of approximately $3.7 billion recorded on our proved oil and natural gas properties during the fourth quarter of 2025.

•Our cash operating costs were $10.23 per BOE, including lease operating expenses of $5.55 per BOE, cash general and administrative expenses of $0.62 per BOE and production and ad valorem taxes and gathering, processing and transportation expenses of $4.06 per BOE.

•Incurred cash capital expenditures, excluding acquisitions, of $3.5 billion.

•Paid dividends to stockholders of $1.2 billion during 2025 and declared a base cash dividend payable in the first quarter of 2026 of $1.05 per share of common stock.

•Increased our common stock repurchase program authorization to $8.0 billion, excluding excise taxes, and repurchased $2.0 billion of our common stock in 2025, leaving approximately $2.7 billion available for future repurchases at December 31, 2025.

•Issued $1.2 billion aggregate principal amount of 5.550% Senior Notes due April 1, 2035 (the “2035 Notes”) to fund a portion of the cash consideration for the Double Eagle Acquisition.

•Repurchased an aggregate of approximately $455 million of our senior notes.

•Our average production was 921.0 MBOE/d.

•Drilled 463 gross horizontal wells (including 459 in the Midland Basin and 4 in the Delaware Basin).

•Turned 503 gross operated horizontal wells (including 488 in the Midland Basin and 15 in the Delaware Basin) to production.

•As of December 31, 2025, we had approximately 869,036 net acres in the Permian Basin, which primarily consisted of 774,645 net acres in the Midland Basin and 94,391 net acres in the Delaware Basin. As of December 31, 2025, we had an estimated 8,854 gross horizontal locations that we believe to be economic at $50.00 per Bbl WTI. Our publicly traded subsidiary, Viper, also owns mineral interests underlying approximately 36,004 net royalty acres in the Delaware Basin and approximately 50,595 net royalty acres in the Midland Basin. We operate approximately 35% of these net royalty acres.

Transactions and Recent Developments

Diamondback Acquisition and Divestitures

EPIC Divestiture

On October 31, 2025, we divested our 27.5% equity interest in EPIC for approximately $504 million in cash and an additional $96 million in contingent consideration (the “EPIC Divestiture”), which resulted in a gain on the sale of equity method investments of approximately $299 million. The gain is included in the caption “Other income (expense), net” on the consolidated statements of operations for the year ended December 31, 2025.

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Divestiture of Water Assets to Deep Blue

On October 1, 2025, we divested EDS, a subsidiary originally acquired in connection with the Endeavor Acquisition, to our affiliate, Deep Blue Midland Basin LLC (“Deep Blue”), in exchange for upfront net cash proceeds of $694 million, subject to customary post-closing adjustments, and approximately $34 million of additional equity interests issued by Deep Blue as non-cash consideration. This transaction provides for the potential for us to earn up to an additional $200 million. If certain completion thresholds are not met, we could owe up to $150 million in contingent consideration for the years 2026 through 2028. The divestiture resulted in a gain of approximately $168 million, which is included in the caption “Other operating expenses, net” on the consolidated statements of operations for the year ended December 31, 2025. As part of the divestiture, we renewed our 15-year dedication to Deep Blue for its produced water and supply water within a 12-county area of mutual interest in the Midland Basin.

2025 Drop Down

On May 1, 2025, our wholly owned subsidiary, EER LP, divested the Endeavor Subsidiaries to Viper and Viper LLC in exchange for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69.63 million Viper LLC units and an equal number of shares of Viper’s Class B common stock.

Double Eagle Acquisition

On April 1, 2025, we completed the Double Eagle Acquisition for consideration of $3.1 billion in cash and approximately 6.84 million shares of our common stock, including transaction costs and certain customary post-closing adjustments. The Double Eagle Acquisition consisted of approximately 67,700 gross (40,000 net) acres, which are primarily located in the Midland Basin, and approximately 407 gross (342 net) horizontal locations in primary development targets.

Viper Acquisitions and Divestitures

Divestiture of Non-Permian Assets

On February 9, 2026, Viper completed the Viper 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 Viper Non-Permian Divestiture were used to repay the Viper 2025 Term Loan (as defined below) and to reduce borrowings outstanding on the Viper Revolving Credit Facility (as defined and discussed in Note 8—Debt in Item 8. Financial Statements and Supplementary Data of this report).

Sitio Acquisition

On August 19, 2025, Viper and Viper LLC 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.

See Note 4—Acquisitions and Divestitures and Note 16—Subsequent Events in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the acquisitions and divestitures discussed above.

Diamondback Capital Transactions

2025 Term Loan Agreement

In connection with the Double Eagle Acquisition, Diamondback Energy, Inc., as guarantor, entered into a term loan credit agreement with Diamondback E&P, as borrower, and Bank of America, N.A., as administrative agent (the “2025 Term Loan”). The 2025 Term Loan provided the Company with the ability to borrow up to $1.5 billion, which we drew in a single borrowing to fund a portion of the cash consideration for the Double Eagle Acquisition.

2035 Notes Offering

On March 20, 2025, we issued the 2035 Notes for net proceeds of $1.2 billion, after underwriters’ discounts and transaction costs, which we used to fund a portion of the cash consideration for the Double Eagle Acquisition.

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Diamondback Retirement of Notes

During the year ended December 31, 2025, we opportunistically repurchased an aggregate principal amount of $455 million of our senior notes in open market transactions for total cash consideration, including accrued interest paid, of approximately $363 million, at an average of 79.3% of par value.

Viper Capital Transactions

Viper 2025 Notes Offering and Retirement of Notes

On July 23, 2025, Viper LLC issued $1.6 billion in aggregate principal amount of senior notes consisting of (i) $500 million aggregate principal amount of 4.900% Senior Notes due August 1, 2030 (the “Viper 2030 Notes”), and (ii) $1.1 billion aggregate principal amount of 5.700% Senior Notes due August 1, 2035 (the “Viper 2035 Notes” and together with the Viper 2030 Notes, the “Viper 2025 Notes”). Viper used approximately $824 million of the net proceeds from the issuance of the Viper 2025 Notes to redeem all of Viper’s 7.375% Senior Notes maturing on November 1, 2031 (the “Viper 2031 Notes”), and on November 1, 2025, Viper redeemed all of their 5.375% Senior Notes due 2027 (the “Viper 2027 Notes”), including accrued and unpaid interest through the date of redemption and any redemption premiums. Viper 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. On December 23, 2025, Viper Energy Partners LLC converted its legal form (the “Viper LLC 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 under the Viper 2025 Notes.

Viper 2025 Term Loan

On July 23, 2025, Former Viper, as guarantor, Viper LLC, as borrower, and Goldman Sachs Bank USA, as administrative agent, entered into a $500 million term loan credit agreement (the “Viper 2025 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 Viper 2025 Term Loan. Further, after the Viper LLC Conversion, Viper LP, as successor to Viper Energy Partners LLC, became the borrower with respect to the Viper 2025 Term Loan. The Viper 2025 Term Loan was repaid in full in February 2026.

Viper 2025 Equity Offering

On February 3, 2025, Viper completed an underwritten public offering of approximately 28.34 million shares of its Class A common stock, which included approximately 3.70 million shares issued pursuant to an option to purchase additional shares of its Class A common stock granted to the underwriters at a price to the public of $44.50 per share, for total net proceeds to Viper of approximately $1.2 billion, after the underwriters’ discount and transaction costs (the “Viper 2025 Equity Offering”).

See Note 8—Debt and Note 9—Stockholders’ Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the capital transactions above.

Commodity Prices

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. 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.

Given the overall decline in SEC Prices through 2025 as compared to 2024, we believe a material non-cash impairment of our assets is reasonably likely to occur in the first quarter of 2026. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine

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an estimate of the amount or range of amounts of any potential impairment charge in the first quarter of 2026. Impairment charges affect our results of operations but do not reduce our cash flow.

For additional information around risks related to commodity prices, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.

Outlook

Our cash capital expenditures for 2025 were consistent with our guidance presented in November 2025. Given the soft outlook for oil prices currently, our 2026 plan is to keep activity and production essentially flat relative to our fourth quarter 2025 levels at approximately 926 MBOE/d to 962 MBOE/d, as adjusted for the impact of the Viper Non-Permian Divestiture. We have currently budgeted 2026 total cash capital spend of $3.60 billion to $3.90 billion, which at the midpoint is an increase of 7% from our 2025 cash capital budget. In 2026, we will continue to target an industry‑leading breakeven oil price by capturing incremental technical and operational efficiencies, driving higher margins and maximizing Adjusted Free Cash Flow to fund our dividend, opportunistically repurchase shares, and continue strengthening the balance sheet.

Our board of directors has approved a return of capital commitment to our shareholders of at least 50% of our quarterly Adjusted Free Cash Flow. We exceeded our commitment to sell at least $1.5 billion of non-core assets during 2025 to help accelerate debt reduction and maintain a strong balance sheet. We also remain focused on our long-term priority to return cash to our stockholders.

In 2025, we successfully delineated the Barnett/Woodford zone across our Midland Basin acreage, confirming reservoir continuity and improving our development line of sight, which will add meaningful incremental drilling locations to our inventory. As a result, we plan to allocate approximately 3% to 4% of our 2026 total capital budget to further advance the Barnett/Woodford across our acreage.

As of December 31, 2025, we were operating 15 drilling rigs and four completion crews and currently intend to operate between 15 and 18 drilling rigs and approximately five completion crews in 2026 on average across our current acreage position in the Midland and Delaware Basins.

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Results of Operations

For a discussion of the results of operations for the year ended December 31, 2024 as compared to the year ended December 31, 2023, please refer to 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), which is incorporated in this report by reference from such prior report on Form 10-K.

Comparison of the Years Ended December 31, 2025 and 2024

The following table sets forth selected historical operating data for the periods indicated:

Year Ended December 31,

2025

2024

Revenues (in millions):

Oil sales

$

11,621 

$

9,067 

Natural gas sales

400 

89 

Natural gas liquid sales

1,432 

944 

Total oil, natural gas and natural gas liquid revenues

$

13,453 

$

10,100 

Production Data:

Oil (MBbls)

181,462 

123,325 

Natural gas (MMcf)

447,855 

275,680 

Natural gas liquids (MBbls)

80,073 

49,700 

Combined volumes (MBOE)(1)

336,178 

218,972 

Daily oil volumes (BO/d)

497,156 

336,954 

Daily combined volumes (BOE/d)

921,036 

598,284 

Average Prices:

Oil ($ per Bbl)

$

64.04 

$

73.52 

Natural gas ($ per Mcf)

$

0.89 

$

0.32 

Natural gas liquids ($ per Bbl)

$

17.88 

$

18.99 

Combined ($ per BOE)

$

40.02 

$

46.12 

Oil, hedged ($ per Bbl)(2)

$

63.14 

$

72.68 

Natural gas, hedged ($ per Mcf)(2)

$

1.84 

$

0.91 

Natural gas liquids, hedged ($ per Bbl)(2)

$

17.88 

$

18.99 

Average price, hedged ($ per BOE)(2)

$

40.79 

$

46.38 

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

(2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.

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Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following table provides information on the mix of our production for the periods indicated:

Year Ended December 31,

2025

2024

Oil (MBbls)

54 

%

56 

%

Natural gas (MMcf)

22 

%

21 

%

Natural gas liquids (MBbls)

24 

%

23 

%

100 

%

100 

%

See Items 1 and 2. Business and Properties—Oil and Natural Gas Data—Oil and Natural Gas Production and Price History of this report for further discussion of production by basin.

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

Our oil, natural gas and natural gas liquids revenues increased by approximately $3.4 billion, or 33%, to $13.5 billion in 2025 compared to 2024. This net increase consisted of an additional $4.9 billion attributable to the 54% growth in our combined production volumes, partially offset by a net reduction of $1.6 billion primarily due to lower average prices received for our oil production.

Approximately 42% of the growth in our combined production volumes is attributable to new wells added between periods, 41% of the increase is attributable to the Endeavor Acquisition and 12% is attributable to the Double Eagle Acquisition.

See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the Endeavor Acquisition and the Double Eagle Acquisition.

Net Sales of Purchased Oil. We enter into purchase transactions with third parties and separate sale transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments.

The following table presents the net sales of purchased oil from third parties for the periods indicated:

Year Ended December 31,

(In millions)

2025

2024

Sales of purchased oil

$

1,476 

$

923 

Purchased oil expense

1,474 

921 

Net sales of purchased oil

$

2 

$

2 

Other Revenues. The following table shows the other revenues for the periods indicated:

Year Ended December 31,

(In millions)

2025

2024

Other operating income

$

97 

$

43 

Other operating income increased by $54 million in 2025 compared to 2024 primarily due to (i) a $35 million increase in midstream revenues attributable to assets acquired in the Endeavor Acquisition, and (ii) a $19 million increase in lease bonus income received during 2025.

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Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated:

Year Ended December 31,

2025

2024

(In millions, except per BOE amounts)

Amount

Per BOE

Amount

Per BOE

Lease operating expenses

$

1,865 

$

5.55 

$

1,286 

$

5.87 

Lease operating expenses increased by $579 million in 2025 compared to 2024. The increase primarily consists of (i) $368 million of costs associated with operating wells acquired in the Endeavor Acquisition and the Double Eagle Acquisition, (ii) $114 million in additional well workover, artificial lift, maintenance and utility costs, (iii) $66 million of additional costs related to higher legacy production volumes, (iv) $23 million in additional expense due to an increase in our average working interest, and (v) other individually insignificant changes. Currently, we estimate expenditures for lease operating expenses may range between approximately $2.0 billion and $2.2 billion in 2026 at the midpoint of expected production.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the periods indicated:

Year Ended December 31,

2025

2024

(In millions, except per BOE amounts)

Amount

Per BOE

Percentage of Oil, Natural Gas and Natural Gas Liquids Revenue

Amount

Per BOE

Percentage of Oil, Natural Gas and Natural Gas Liquids Revenue

Production taxes

$

634 

$

1.89 

4.7 

%

$

462 

$

2.11 

4.6 

%

Ad valorem taxes

217 

0.64 

1.6 

176 

0.80 

1.7 

Total production and ad valorem expense

$

851 

$

2.53 

6.3 

%

$

638 

$

2.91 

6.3 

%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices and ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. For 2025 compared to 2024, both production taxes and ad valorem taxes as a percentage of oil, natural gas and natural gas liquids revenues remained relatively flat. Rates per BOE for both production taxes and ad valorem taxes declined primarily due to the increase in production volumes for 2025 compared to 2024.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expense for the periods indicated:

Year Ended December 31,

2025

2024

(In millions, except per BOE amounts)

Amount

Per BOE

Amount

Per BOE

Gathering, processing and transportation

$

515 

$

1.53 

$

356 

$

1.63 

Gathering, processing and transportation expense increased by $159 million in 2025 compared to 2024 primarily due to (i) $54 million incurred on additional production acquired in the Endeavor Acquisition, (ii) an additional $44 million in transportation costs incurred to meet our minimum volume commitments on certain pipelines, (iii) $34 million associated with production from new wells completed between 2025 and 2024, (iv) $18 million related to new firm transportation contracts that became effective during 2025, and (v) other individually insignificant changes. Currently, we estimate expenditures for gathering, processing and transportation may range between approximately $507 million and $597 million in 2026 at the midpoint of expected production.

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Depreciation, Depletion, Amortization and Accretion. The following table shows the components of our depreciation, depletion and amortization expense for the periods indicated:

Year Ended December 31,

(In millions, except BOE amounts)

2025

2024

Depletion of proved oil and natural gas properties

$

4,908 

$

2,759 

Depreciation of other property and equipment

86 

61 

Other amortization

9 

8 

Asset retirement obligation accretion

35 

22 

Depreciation, depletion, amortization and accretion expense

$

5,038 

$

2,850 

Oil and natural gas properties depletion rate per BOE

$

14.60 

$

12.60 

Depreciation, depletion, amortization and accretion per BOE

$

14.99 

$

13.02 

The increase in depletion of proved oil and natural gas properties of $2.1 billion in 2025 as compared to 2024 consists primarily of $1.5 billion from growth in production volumes and $672 million due to an increase in the depletion rate resulting largely from the addition of higher value leasehold costs and proved reserves from the Endeavor Acquisition, the Double Eagle Acquisition and, to a lesser extent, Viper’s Sitio Acquisition and Viper’s Tumbleweed Acquisitions (as defined and discussed in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report).

Impairment of Oil and Natural Gas Properties. The following table shows impairment of oil and natural gas properties for the periods indicated:

Year Ended December 31,

(In millions)

2025

2024

Impairment of oil and natural gas properties

$

3,652 

$

— 

The non-cash ceiling test impairment charge of $3.7 billion for the year ended December 31, 2025 primarily resulted from the decline in SEC Prices during 2025. 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, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. 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 the components of general and administrative expenses for the periods indicated:

Year Ended December 31,

2025

2024

(In millions, except per BOE amounts)

Amount

Per BOE

Amount

Per BOE

General and administrative expenses

$

207 

$

0.62 

$

148 

$

0.68 

Non-cash stock-based compensation

81 

0.24 

65 

0.30 

Total general and administrative expenses

$

288 

$

0.86 

$

213 

$

0.98 

The increase in general and administrative expenses of $59 million in 2025 compared to 2024 was primarily due to a $47 million increase in employee compensation and benefit costs related to increasing headcount largely from the Endeavor Acquisition for the full year of 2025 and other individually insignificant items.

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Other Operating Expenses. The following table shows other operating expenses for the periods indicated:

Year Ended December 31,

(In millions)

2025

2024

Other operating expenses, net

$

77 

$

406 

Other operating expenses decreased by $329 million in 2025 compared to 2024 primarily due to (i) a $198 million reduction in merger and transaction costs largely due to 2024 including $303 million in costs associated with the Endeavor Acquisition compared to $105 million of costs incurred in 2025 for transactions including the 2025 Drop Down, Viper’s Sitio Acquisition and additional severance and other costs for the Endeavor Acquisition, (ii) a $168 million gain on the sale of our EDS subsidiary during the fourth quarter of 2025, and (iii) other individually insignificant expenses. These decreases were partially offset by a $38 million increase in midstream costs incurred in connection with EDS prior to its sale in the fourth quarter of 2025.

Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash received (paid) on settlements of derivative instruments for the periods indicated:

Year Ended December 31,

(In millions)

2025

2024

Gain (loss) on derivative instruments, net

$

341 

$

137 

Net cash received (paid) on settlements(1)

$

181 

$

(51)

(1)Includes cash paid on interest rate swaps terminated prior to their contractual maturity of $67 million for 2025 and $37 million for 2024.

The increase in gain on derivative instruments for the year ended December 31, 2025, compared to the same period in 2024 primarily reflects (i) a $118 million net gain on natural gas contracts, which was comprised of a $262 million increase in cash received on the settlement of contracts partially offset by a $144 million decrease in the value of our unsettled natural gas contracts primarily due to an increase in market prices for natural gas compared to our contract prices, (ii) an $89 million gain on our interest rate swaps, which was comprised of a $59 million increase in the value of our unsettled interest rate swap contracts primarily due to a decline in expected future interest rates and the early termination of $600 million in notional amount of the interest rate swaps in 2025 and a $30 million net decrease in cash paid for the settlement and early termination of our interest rate derivatives and treasury locks, and (iii) other individually insignificant changes.

See Note 12—Derivatives in Item 8. Financial Statements and Supplementary Data of this report for further details regarding our derivative instruments and interest rate swaps.

Other Income (Expense). The following table shows other income and expenses for the periods indicated:

Year Ended December 31,

(In millions)

2025

2024

Interest expense, net

$

(244)

$

(135)

Other income (expense), net

$

455 

$

101 

Gain (loss) on extinguishment of debt

$

56 

$

2 

Interest expense, net increased by $109 million in 2025, compared to 2024. This increase primarily consisted of (i) a $131 million reduction in interest income (which reduces interest expense) attributable to holding funds raised for the Endeavor Acquisition in cash in short-term interest bearing accounts during the year ended December 31, 2024, (ii) $111 million of interest expense on the 2025 Term Loan and 2035 Notes, which were both issued in March 2025, (iii) $91 million of additional interest expense on the April 2024 Notes, and (iv) a net $31 million increase related to Viper comprised of additional interest expense on the Viper 2025 Notes and Viper 2025 Term Loan partially offset by a reduction in interest expense attributable to Viper’s redemption of the Viper 2027 Notes and the Viper 2031 Notes. These increases were partially offset by (i) a $237 million increase in capitalized interest costs, which reduces interest expense, (ii) a $24 million reduction in amortization of debt issuance costs primarily related to fully amortizing costs related to our bridge facility in 2024 upon its termination, and (iii) other individually insignificant offsetting changes. Currently, we estimate expenditures for interest expense, net may range between approximately $237 million and $316 million in 2026.

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See Note 8—Debt in Item 8. Financial Statements and Supplementary Data of this report for further details regarding outstanding borrowing, interest expense and gain (loss) on extinguishment of debt.

Other income for the year ended December 31, 2025, increased by $354 million compared to the same period in 2024, primarily due to an increase of $363 million in the gain recognized on the sale of various equity method investments in 2025 compared to 2024. This net gain was partially offset by a $30 million decrease in the value of an investment recorded at fair value during 2025, compared to 2024 and other individually insignificant items.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the periods indicated:

Year Ended December 31,

(In millions)

2025

2024

Provision for (benefit from) income taxes

$

327 

$

800 

The reduction in our income tax provision for 2025 compared to 2024 was primarily due to the decrease in pre-tax income resulting largely from the non-cash ceiling test impairment recognized in 2025. See Note 11—Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our income tax expense.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Historically, our primary sources of liquidity have included cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility and term loan agreements, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties, repayment of debt and returning capital to stockholders. At December 31, 2025, we had approximately $2.6 billion of liquidity consisting of $91 million in standalone cash and cash equivalents and $2.5 billion available under our credit facility. As discussed below, our cash capital budget guidance for 2026 is approximately $3.60 billion to $3.90 billion, which prioritizes free cash flow generation and debt reduction. As of December 31, 2025, we had approximately $763 million of senior notes maturing in the next 12 months.

Future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the volatility of commodity prices. Further, significant additional capital expenditures will be required to more fully develop our properties. Prices for our commodities are determined primarily by prevailing market conditions, regional and worldwide economic activity, weather and other substantially variable factors. These factors are beyond our control and are difficult to predict. See Item 1A. Risk Factors of this report above. In order to mitigate this volatility, we enter into derivative contracts with a number of financial institutions, all of which are participants in our credit facility, to economically hedge a portion of our estimated future crude oil and natural gas production as discussed further in Note 12—Derivatives in Item 8. Financial Statements and Supplementary Data and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of this report. The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.

Cash Flow

Our cash flows for the years ended December 31, 2025 and 2024 are presented below:

Year Ended December 31,

2025

2024

(In millions)

Net cash provided by (used in) operating activities

$

8,758 

$

6,413 

Net cash provided by (used in) investing activities

(7,809)

(11,221)

Net cash provided by (used in) financing activities

(1,007)

4,387 

Net change in cash

$

(58)

$

(421)

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Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce.

The increase in operating cash flows for the year ended December 31, 2025 compared to the same period in 2024 primarily resulted from (i) $3.4 billion in additional revenue, excluding sales of purchased oil, and (ii) an increase of $232 million of cash received on settlements of derivatives in 2025 compared to cash paid on settlements of derivatives in 2024, and a reduction of $114 million in cash paid for interest, net of capitalized amounts. These cash inflows were partially offset by (i) higher cash operating expenses, excluding purchased oil expense, of approximately $483 million, (ii) an increase of $629 million in cash paid for taxes, and (iii) fluctuations in other working capital balances due primarily to the timing of when collections were made on accounts receivable and payments were made on accounts payable. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

The majority of our net cash used in investing activities during the year ended December 31, 2025, was for drilling and completion costs in conjunction with our development program as well as the acquisition of properties and equipment for the Double Eagle Acquisition and Viper’s Sitio Acquisition. The majority of our net cash used in investing activities during the year ended December 31, 2024, was for the Endeavor Acquisition. These cash outflows were partially offset by proceeds received from the divestitures of various oil and gas properties and other assets including EDS and the EPIC Divestiture, which are discussed further in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report.

Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:

Year Ended December 31,

2025

2024

(In millions)

Operated drilling and completion additions to oil and natural gas properties

$

(2,951)

$

(2,617)

Capital workovers, non-operated additions to oil and natural gas properties and science

(335)

(15)

Infrastructure, environmental and midstream additions

(237)

(235)

Total

$

(3,523)

$

(2,867)

For further discussion regarding our development program, please see Items 1 and 2. Business and Properties—Oil and Natural Gas Data—Wells Drilled and Completed in 2025 of this report.

Financing Activities

During the year ended December 31, 2025, net cash used in financing activities was primarily attributable to (i) $2.2 billion of repurchases as part of our and Viper’s repurchase programs, (ii) $1.9 billion to repay and retire our Tranche A Loans and partially repay the 2025 Term Loan, (iii) $1.2 billion of dividends paid to stockholders, (iv) $1.2 billion paid for the retirement of certain of our and Viper’s senior notes, (v) $382 million in dividends paid to non-controlling interest, (vi) and various other individually insignificant costs. These cash outflows were partially offset by (i) $2.8 billion of proceeds from the issuance of the 2035 Notes and Viper 2025 Notes, (ii) $2.0 billion of aggregate proceeds from the 2025 Term Loan and the Viper 2025 Term Loan, (iii) $1.2 billion in proceeds from the Viper 2025 Equity Offering, and (iv) $156 million in borrowings on our credit facilities, net of repayments.

During the year ended December 31, 2024, net cash provided by financing activities was primarily attributable to (i) $5.5 billion of proceeds from the issuance of the April 2024 Notes, (ii) $900 million in borrowings on our Tranche A Loans, net of repayments, (iii) $476 million in proceeds from the Viper 2024 Equity Offering (as defined and discussed in Note 9—Stockholders’ Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report), (iv) $451 million in proceeds from the sale of our shares of Viper’s Class A common stock, and (v) $2 million in borrowings on our credit facilities, net of repayments. These cash inflows were partially offset by (i) $1.6 billion of dividends paid to stockholders, (ii) $959 million of repurchases as part of our and Viper’s share repurchase programs, (iii) $227 million in

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distributions to non-controlling interest, (iv) $99 million of debt issuance costs primarily associated with the April 2024 Notes and Tranche A Loans, and (v) $39 million in cash paid for tax withholdings on vested employee stock awards.

Capital Resources

Our working capital requirements are primarily supported by our cash and cash equivalents and available borrowings under our revolving credit facility. We may draw on our 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, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term capital requirements.

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, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Any prolonged volatility in the capital, financial and/or credit markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Revolving Credit Facilities

Diamondback’s Credit Agreement

As of December 31, 2025, the maximum credit amount available under our undrawn revolving credit facility was $2.5 billion, which may be increased to a total maximum commitment amount of $2.6 billion and has a maturity date of June 12, 2030.

Viper’s Revolving Credit Facility

In 2025, Former Viper, as guarantor, entered into a credit agreement with Viper LLC, as borrower, and Wells Fargo, as the administrative agent (the “Viper Revolving Credit Facility”), which matures on June 12, 2030, and provides for a commitment amount of $1.5 billion. As of December 31, 2025, the Viper Revolving Credit Facility had $105 million in outstanding borrowings and $1.4 billion available for future borrowings. Following the Viper LLC Conversion, Viper LP, as successor to Viper Energy Partners LLC, became the borrower with respect to the Viper Revolving Credit Facility.

For additional discussion of our outstanding debt as of December 31, 2025, see Note 8—Debt in Item 8. Financial Statements and Supplementary Data of this report.

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. 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 (Baa2).

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

Capital Requirements

In addition to future operating expenses and working capital commitments discussed in “—Outlook,” our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of principal and interest on our revolving credit facility, 2025 Term Loan and senior notes, (iii) payments of other contractual obligations, and (iv) cash used to pay for dividends and repurchases of securities.

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2026 Capital Spending Plan

We currently estimate that our 2026 cash capital budget will be $3.60 billion to $3.90 billion, which includes $3.05 billion to $3.27 billion for operated horizontal drilling and completions.

The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget up or down in response to changes in commodity prices and overall market conditions.

Payments of Principal and Interest on Debt Instruments

As of December 31, 2025, our debt, including the debt of Viper, consisted of approximately $13.5 billion in aggregate outstanding principal amount of senior notes, $550 million outstanding under the 2025 Term Loan due in 2027, $500 million outstanding under the Viper 2025 Term Loan due in 2027, which was repaid in February 2026, and $105 million in outstanding borrowings under the Viper Revolving Credit Facility, which was repaid in the first quarter of 2026.

At December 31, 2025, we have total principal payments due on our outstanding senior notes, including those of Viper, of $763 million in 2026, $850 million in 2027, $73 million in 2028, $915 million in 2029, $1.4 billion in 2030 and $9.6 billion thereafter. Additionally, we expect to incur future cash interest costs on these senior notes of approximately $693 million in 2026, $1.3 billion cumulatively in the years from 2027 through 2028, $1.2 billion cumulatively in the years from 2029 and 2030, and $6.8 billion cumulatively between 2031 and 2064.

See Note 8—Debt in Item 8. Financial Statements and Supplementary Data of this report for further details regarding our outstanding borrowing and interest expense.

Other Contractual Obligations and Commitments

At December 31, 2025, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $3.0 billion, (ii) electrical power purchase commitments totaling $495 million, (iii) asset retirement obligations totaling $542 million, (iv) electric fracturing fleet and related power generation services commitments totaling $124 million, (v) compressor rental commitments totaling $90 million, and (vi) minimum purchase commitments for quantities of sand used in our drilling operations totaling $56 million. We expect to make aggregate payments of approximately $586 million for these commitments during 2026. See Note 6—Asset Retirement Obligations and Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report for further discussion of these and other contractual obligations and commitments.

We and Five Point Energy LLC currently anticipate collectively contributing $500 million in follow-on capital to fund future growth in our Deep Blue Midland Basin LLC joint venture projects and acquisitions.

Return of Capital Commitment

Our board of directors has approved a return of capital commitment of at least 50% of our quarterly Adjusted Free Cash Flow to our stockholders through repurchases under our share repurchase program, base dividends and variable dividends. The remainder of our Adjusted Free Cash Flow will be used primarily to reduce debt. On February 19, 2026, our board of directors declared a base cash dividend for the fourth quarter of 2025 of $1.05 per share of common stock.

Future base and variable dividends are at the discretion of our board of directors, and the board of directors may change the dividend amount from time to time based on our outlook for commodity prices, liquidity, debt levels, capital resources, Adjusted Free Cash Flow and other factors. We can provide no assurance that dividends will be authorized or declared in the future or as to the amount and type of any future dividends. Any future dividends, whether base or variable, if declared and paid, will by their nature fluctuate based on our free cash flow, which will depend on a number of factors beyond our control, including commodity prices.

On July 31, 2025, our board of directors approved an increase in our common stock repurchase program from $6.0 billion to $8.0 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 the stock repurchase program through February 20, 2026, we

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have repurchased an aggregate 40.69 million shares of our common stock for a total cost of $5.7 billion, which includes $637 million for the repurchase of 4.0 million shares from SGF, excluding excise tax, leaving approximately $2.3 billion for future repurchases under such stock repurchase program. Subject to regulatory restrictions and other factors discussed elsewhere in this report, we intend to continue to purchase shares under this repurchase program opportunistically with available funds primarily from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs; however, the stock repurchase program is at the discretion of our board of directors and can be amended, terminated or suspended at any time. Repurchases may be executed in privately negotiated or open-market transactions, consistent with Rule 10b-18 under the Securities Exchange Act of 1934 and other applicable requirements. All shares repurchased will be retired. See Note 9—Stockholders’ Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our stock repurchase program.

Guarantor Financial Information

Diamondback E&P is the sole guarantor under the indentures governing the outstanding Guaranteed Senior Notes.

Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the indentures governing the Guaranteed Senior Notes, such as, with certain exceptions, (i) in the event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (ii) in the event Diamondback E&P ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (iii) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.

Diamondback E&P’s guarantees of the Guaranteed Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Guaranteed Senior Notes against Diamondback E&P may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback E&P’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback E&P, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary, and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.

December 31, 2025

Summarized Balance Sheets:

(In millions)

Assets:

Current assets

$

844 

Property and equipment, net

$

19,670 

Other noncurrent assets

$

142 

Liabilities:

Current liabilities

$

3,304 

Intercompany accounts payable, non-guarantor subsidiary

$

6,970 

Long-term debt

$

11,540 

Other noncurrent liabilities

$

2,186 

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Year Ended December 31, 2025

Summarized Statement of Operations:

(In millions)

Revenues

$

6,765 

Income (loss) from operations(1)

$

(1,296)

Net income (loss)

$

(1,001)

(1)During the year ended December 31, 2025, the Company recorded a significant noncash impairment that is reflected in the summarized results of the guarantor group. This impairment is not indicative of cash flows available for debt service.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

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 and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates and assumptions on a regular basis. Critical accounting estimates are those estimates made in accordance with generally accepted accounting principles that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on the financial condition or results of operations of the registrant. 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.

Oil and Natural Gas Accounting and Reserves

We account for our 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 proved oil and natural gas properties including 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 Company, L.P., 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 our estimate of operating and development costs, 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 reported reserve estimates 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. Revisions of previous reserve estimates accounted for approximately $4.2 billion, or 143% of the net change in the standardized measure of our total reserves from December 31, 2024 to December 31, 2025. The Company recorded a material impairment during the year ended December 31, 2025 as discussed in Note 5—Property and Equipment in Item 8. Financial Statements and Supplementary Data of this report. No impairments were recorded for our proved oil and gas properties during the years ended December 31, 2024 and 2023. Based on the historical 12-month average trailing SEC prices

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for oil and natural gas throughout 2025 and into 2026, we are currently projecting a material full cost ceiling impairment in the first quarter of 2026. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. 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. Impairment charges affect our results of operations but do not reduce our cash flow.

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) intent to drill, (ii) remaining lease term, (iii) geological and geophysical evaluations, (iv) drilling results and activity, (v) the assignment of proved reserves, and (vi) the economic viability of development if proved reserves are assigned. At December 31, 2025, our unevaluated properties totaled $23.9 billion, which consisted of 408,284 net undeveloped leasehold acres with approximately 10,902 net acres set to expire in 2026 if no action is taken to develop or extend. We had no significant impairment losses on our unevaluated properties during the year ended December 31, 2025, but any such future impairment could potentially be material to our consolidated financial statements.

Business Combinations

We account for business combinations in which it has been determined we are the acquirer using the acquisition method of accounting. Accordingly, identifiable assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. Fair value estimates are determined based on information that existed at the time of the acquisition, utilizing expectations and assumptions that would be available to and made by a market participant. When market-observable prices are not available to value assets and liabilities, the Company may use the cost, income, or market valuation approaches depending on the quality of information available to support management’s assumptions.

The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. The assumptions made in performing these valuations include future production volumes, future commodity prices and costs, future operating and development activities, projections of oil and gas reserves and a weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of natural gas and oil properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Changes in key assumptions may cause the acquisition accounting to be revised, including the recognition of goodwill or discount on an acquisition. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected. See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the estimated fair value of assets acquired and liabilities assumed in business combinations including any significant changes in these estimates from the date of acquisition.

Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. In addition, differences between the future commodity prices when acquiring assets and the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net earnings.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and local 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 the

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Company. Negative evidence may include losses in recent years, if any, or the projection of losses in future periods. The assessment of the realizability of our deferred tax assets, including the assessment of whether a valuation allowance is required, entails that we make estimates of, and assumptions about, future events, including the pattern of reversal of taxable temporary differences and our future income from operations. Estimating future taxable income requires numerous judgments and assumptions, including projections of future operating conditions which may be impacted by volatile future prices for our oil, natural gas and natural gas production, the expected timing and quantity of future production volumes, and the impact of our commodity derivative instruments on our income.

In 2025, management’s assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets as required by applicable accounting standards, supported the conclusion that Viper’s deferred tax assets are more likely than not to be realized. The positive evidence assessed included recent cumulative income due in part to commodity prices remaining at a profitable level, acquisitions of additional oil and gas properties, and an expectation of future taxable income based upon recent actual and forecasted production volumes and prices. As of December 31, 2025, Viper had a net deferred tax asset of $33 million. Any changes in the positive or negative evidence evaluated when determining if Viper’s deferred tax assets will be realized, including projected future income, could result in a material change to our consolidated financial statements. As of December 31, 2025, our balance of taxable temporary differences anticipated to reverse within the carryforward period provides significant positive evidence for the determination that our remaining deferred tax assets are more likely than not to be realized.

The accruals for deferred tax assets and liabilities are often based on unclear tax positions and 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. At December 31, 2025, we had no uncertain tax positions; however, 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 recent accounting pronouncements not yet adopted, if any.

Off-Balance Sheet Arrangements

See Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report for a discussion of our significant commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.