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What changed in Diamondback Energy's 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of Diamondback Energy's 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+465 added−498 removedSource: 10-K (2026-02-25) vs 10-K (2025-02-26)

Top changes in Diamondback Energy's 2025 10-K

465 paragraphs added · 498 removed · 324 edited across 6 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

42 edited+40 added−40 removed4 unchanged
Biggest changeFinancial Statements and Supplementary Data of this report for further discussion. 2024 Financial and Operating Highlights • We recorded net income of $3.3 billion. • Increased our annual base dividend to $4.00 per share of common stock in the fourth quarter of 2024, paid dividends to stockholders of $1.6 billion during 2024 and declared a base cash dividend payable in the first quarter of 2025 of $1.00 per share of common stock. • Increased our common stock repurchase program authorization to $6.0 billion, excluding excise taxes, and repurchased $959 million of our common stock, leaving approximately $2.7 billion available for future purchases under our common stock repurchase program at December 31, 2024. • Our cash operating costs were $11.09 per BOE, including lease operating expenses of $5.87 per BOE, cash general and administrative expenses of $0.68 per BOE and production and ad valorem taxes and gathering, processing and transportation expenses of $4.54 per BOE. • Issued the April 2024 Notes for an aggregate of $5.5 billion in proceeds and incurred $1.0 billion in initial borrowings under the Tranche A Loans (as defined below in “— Transactions and Recent Developments ”) to fund a portion of the cash consideration for the Endeavor Acquisition. • Our average production was 598,284 MBOE/d. • Drilled 372 gross horizontal wells (including 342 in the Midland Basin and 30 in the Delaware Basin). • Turned 410 gross operated horizontal wells (including 391 in the Midland Basin and 19 in the Delaware Basin) to production. • As of December 31, 2024, we had approximately 860,719 net acres, which primarily consisted of 737,181 net acres in the Midland Basin and 123,218 net acres in the Delaware Basin.
Biggest changeFinancial 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.
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, 2024, we have one reportable segment, the upstream segment.
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.
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 13— Derivatives in Item 8. Financial Statements and Supplementary Data and
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
(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. 52 Table of Contents Production Data.
(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. 47 Table of Contents Production Data.
See Note 13— 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).
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).
Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties and repayment of debt and returning capital to stockholders. At December 31, 2024, we had approximately $2.6 billion of liquidity consisting of $134 million in standalone cash and cash equivalents and $2.5 billion available under our credit facility.
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.
See Note 12— Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our income tax expense.
See Note 11— Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our income tax expense.
The pending Double Eagle Acquisition consists 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.
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.
See Note 1— Description of the Business and Basis of Presentation and Note 18— Segment Information in Item 8.
See Note 1— Description of the Business and Basis of Presentation and Note 17— Segment Information in Item 8.
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, 2023 (filed with the SEC on February 22, 2024), which is incorporated in this report by reference from such prior report on Form 10-K.
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.
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, issuances of common stock in connection with acquisitions, borrowings under our revolving credit facility, proceeds from the issuance of senior notes and sales of non-core assets.
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.
The following table provides information on the mix of our production for the years ended December 31, 2024 and 2023: Year Ended December 31, 2024 2023 Oil (MBbls) 56 % 59 % Natural gas (MMcf) 21 % 20 % Natural gas liquids (MBbls) 23 % 21 % 100 % 100 % See Items 1 and 2.
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.
The following table presents the net sales of purchased oil from third parties for the year ended December 31, 2024 and 2023: Year Ended December 31, (In millions) 2024 2023 Sales of purchased oil $ 923 $ 111 Purchased oil expense 921 111 Net sales of purchased oil $ 2 $ — Other Revenues.
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 production and ad valorem tax expense for the years ended December 31, 2024 and 2023: Year Ended December 31, 2024 2023 (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 $ 462 $ 2.11 4.6 % $ 380 $ 2.32 4.6 % Ad valorem taxes 176 0.80 1.7 145 0.89 1.8 Total production and ad valorem expense $ 638 $ 2.91 6.3 % $ 525 $ 3.21 6.4 % In general, production taxes are directly related to production revenues and are based upon current year commodity prices.
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.
As of December 31, 2024, we had an estimated 9,188 gross horizontal locations that we believe to be economic at $50.00 per Bbl WTI. In addition, our publicly traded subsidiary, Viper, owns mineral interests underlying approximately 987,861 gross acres and 35,671 net royalty acres in the Permian 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.
Financial Statements and Supplementary Data of this report for further discussion of the Endeavor Acquisition.
Financial Statements and Supplementary Data of this report for further discussion of the acquisitions and divestitures discussed above.
The following table shows lease operating expenses for the years ended December 31, 2024 and 2023: Year Ended December 31, 2024 2023 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Lease operating expenses $ 1,286 $ 5.87 $ 872 $ 5.34 Lease operating expenses increased by $414 million, or $0.53 per BOE in 2024 as compared to 2023.
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 following table shows general and administrative expenses for the years ended December 31, 2024 and 2023: Year Ended December 31, 2024 2023 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE General and administrative expenses $ 148 $ 0.68 $ 96 $ 0.59 Non-cash stock-based compensation 65 0.30 54 0.33 Total general and administrative expenses $ 213 $ 0.98 $ 150 $ 0.92 The increase in general and administrative expenses of $52 million in 2024 compared to 2023 was primarily due to (i) a $41 million increase in employee compensation and benefit costs related to additional headcount largely from the Endeavor Acquisition and annual compensation adjustments, (ii) a $12 million increase in software costs, and (iii) offsetting changes in other individually insignificant items.
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. 50 Table of Contents Other Operating Expenses.
The following table sets forth selected historical operating data for the periods indicated: Year Ended December 31, 2024 2023 Revenues (in millions): Oil sales $ 9,067 $ 7,279 Natural gas sales 89 262 Natural gas liquid sales 944 687 Total oil, natural gas and natural gas liquid revenues $ 10,100 $ 8,228 Production Data: Oil (MBbls) 123,325 96,176 Natural gas (MMcf) 275,680 198,117 Natural gas liquids (MBbls) 49,700 34,217 Combined volumes (MBOE) (1) 218,972 163,413 Daily oil volumes (BO/d) 336,954 263,496 Daily combined volumes (BOE/d) 598,284 447,707 Average Prices: Oil ($ per Bbl) $ 73.52 $ 75.68 Natural gas ($ per Mcf) $ 0.32 $ 1.32 Natural gas liquids ($ per Bbl) $ 18.99 $ 20.08 Combined ($ per BOE) $ 46.12 $ 50.35 Oil, hedged ($/Bbl) (2) $ 72.68 $ 74.72 Natural gas, hedged ($/Mcf) (2) $ 0.91 $ 1.48 Natural gas liquids, hedged ($/Bbl) (2) $ 18.99 $ 20.08 Average price, hedged ($/BOE) (2) $ 46.38 $ 49.98 (1) Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
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.
See Note 9— 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.
Currently, we estimate expenditures for interest expense, net may range between approximately $237 million and $316 million in 2026. 51 Table of Contents 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.
The pending Double Eagle Acquisition is expected to close in the second quarter of 2025, subject to the satisfaction of customary closing conditions and regulatory approval. 47 Table of Contents 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 (the “Viper 2025 Equity Offering”), which included 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.
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”).
This net increase consisted of an additional $2.5 billion attributable to the 34% growth in our combined production volumes, and a reduction of $596 million attributable to lower average prices received for our oil, natural gas and natural gas liquids production.
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.
Our oil, natural gas and natural gas liquids revenues increased by approximately $1.9 billion, or 23%, to $10.1 billion in 2024 compared to $8.2 billion in 2023.
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.
The following table shows the components of our depreciation, depletion and amortization expense for the years ended December 31, 2024 and 2023: Year Ended December 31, (In millions, except BOE amounts) 2024 2023 Depletion of proved oil and natural gas properties $ 2,759 $ 1,669 Depreciation of other property and equipment 61 56 Other amortization 8 6 Asset retirement obligation accretion 22 15 Depreciation, depletion, amortization and accretion expense $ 2,850 $ 1,746 Oil and natural gas properties depletion rate per BOE $ 12.60 $ 10.21 Depreciation, depletion, amortization and accretion per BOE $ 13.02 $ 10.68 The increase in depletion of proved oil and natural gas properties of $1.1 billion in 2024 as compared to 2023 consists of an additional (i) $567 million from the growth in production volumes, and (ii) $523 million due to applying a higher depletion rate in 2024.
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.
See Note 10— Stockholders' Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the Viper 2024 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.
The following table shows the other revenues for the year ended December 31, 2024 and 2023: Year Ended December 31, (In millions) 2024 2023 Other operating income $ 43 $ 73 Other operating income decreased by $30 million in 2024 compared to 2023 primarily due to (i) a $37 million reduction in midstream service revenues following the sale of the Deep Blue Water Assets in the third quarter of 2023, (ii) a $5 million increase in midstream service revenues resulting from the Endeavor Acquisition and (iii) other individually insignificant changes. 53 Table of Contents Lease Operating Expenses.
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. 48 Table of Contents Lease Operating Expenses.
Beginning in the third quarter of 2023, we entered into purchase transactions with third parties and separate sale transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments.
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.
Giving effect to the pending Double Eagle Acquisition, we have currently budgeted 2025 total capital spend of $3.80 billion to $4.20 billion, which at the midpoint is an increase of 36% year over year.
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.
The following table shows the net gain (loss) on derivative instruments and the net cash received (paid) on settlements of derivative instruments for the years ended December 31, 2024 and 2023: Year Ended December 31, (In millions) 2024 2023 Gain (loss) on derivative instruments, net $ 137 $ (259) Net cash received (paid) on settlements (1) $ (51) $ (110) (1) The year ended December 31, 2024 includes cash paid on interest rate swaps terminated prior to their contractual maturity of $37 million and cash paid for the early settlement of treasury lock contracts of $25 million The change from a loss to a gain on derivative instruments in 2024 compared to 2023 primarily reflects (i) a $374 million increase in the value of our unsettled natural gas contracts due to a decrease in market prices for natural gas compared to our contract prices, (ii) a $129 million increase in cash received on the settlement of natural gas contracts, and (iii) a $10 million increase in the value of our interest rate swap contracts primarily due to a decline in expected future interest rates.
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.
Pending 2025 Drop Down Transaction On January 30, 2025, EER LP and the Endeavor Subsidiaries, each of which is our subsidiary, entered into a definitive equity purchase agreement with Viper and Viper LLC to divest the Endeavor Subsidiaries to Viper in exchange for consideration consisting of (i) $1.0 billion in cash and (ii) the issuance of 69.63 million Viper LLC units and an equal number of shares of Viper’s Class B common stock (which securities are exchangeable for an equal number of Viper’s Class A common stock), in each case subject to customary closing adjustments, including for net title benefits.
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.
Transactions and Recent Developments 2025 Transactions Pending Double Eagle Acquisition On February 14, 2025, we entered into a definitive securities purchase agreement with Double Eagle to effect the pending Double Eagle Acquisition for consideration of $3.0 billion in cash and approximately 6.9 million shares of our common stock, subject to customary adjustments.
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.
Our long-term target is to maintain our net debt between $6 billion and $8 billion through free cash flow generation and potential non-core asset sales as demonstrated by our recently announced commitment to sell at least $1.5 billion of non-core assets to help accelerate debt reduction and maintain a strong 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 operate approximately 52% of these net royalty acres. • Incurred capital expenditures, excluding acquisitions, of $2.9 billion.
We operate approximately 35% of these net royalty acres.
The increase primarily consists of (i) $220 million in lease operating expenses related to the Endeavor Acquisition, (ii) $66 million in additional costs incurred for water services as a result of divesting the Deep Blue Water Assets in the third quarter of 2023, (iii) $65 million due to an increase in legacy production volumes, (iv) $48 million due to an increase in workover expense, (v) $12 million due to an increase in electrical generation costs, and (vi) other individually insignificant changes.
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.
The following table shows the provision for (benefit from) income taxes for the years ended December 31, 2024 and 2023: Year Ended December 31, (In millions) 2024 2023 Provision for (benefit from) income taxes $ 800 $ 912 The change in our income tax provision for 2024 compared to 2023 was primarily due to a lower effective annual tax rate following the release of Viper’s $156 million valuation allowance in the fourth quarter of 2024.
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.
The mineral and royalty interests acquired in the Viper Q & M Acquisitions, represent approximately 406 and 267 net royalty acres located primarily in the Permian Basin, respectively. See Note 4— Acquisitions and Divestitures in Item 8.
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.
Approximately 72% of the increase in combined production volumes is attributable to the Endeavor Acquisition, 4% is attributable to Viper’s GRP Acquisition and 1% is attributable to Viper’s Tumbleweed Acquisitions. The remainder of the change is attributable to new wells drilled on previously existing acreage.
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.
The following table shows gathering, processing and transportation expense for the years ended December 31, 2024 and 2023: Year Ended December 31, 2024 2023 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Gathering, processing and transportation $ 356 $ 1.63 $ 287 $ 1.76 Gathering, processing and transportation expense increased by $69 million in 2024 compared to 2023 primarily due to an increase in our production from legacy wells as well as an increase in our contractual rates throughout the year.
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.
Regional and worldwide economic activity, 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.
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.
As discussed below, our capital budget for 2025, which gives effect to the pending Double Eagle Acquisition, is $3.80 billion to $4.20 billion. As of December 31, 2024, we have approximately $900 million of Tranche A Loans maturing in September 2025.
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.
These reductions were largely offset by (i) an increase of $233 million in interest expense on senior notes related primarily to the issuance of the April 2024 Notes and Viper’s 7.375% Senior Notes due 2031 which were issued in the fourth quarter of 2023, (ii) an increase of $39 million in amortization of debt issuance costs primarily related to our terminated Bridge Facility, Tranche A Loans and April 2024 Notes, and (iii) a $19 million increase in interest expense incurred in connection with the Tranche A Loans.
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.
April 2024 Notes Offering On April 18, 2024, we issued an aggregate of $5.5 billion in senior notes, consisting of (i) $850 million aggregate principal amount of 5.200% Senior Notes due April 18, 2027 (the “2027 Notes”), (ii) $850 million aggregate principal amount of 5.150% Senior Notes due January 30, 2030 (the “2030 Notes”), (iii) $1.3 billion aggregate principal amount of 5.400% Senior Notes due April 18, 2034 (the “2034 Notes”), (iv) $1.5 billion aggregate principal amount of 5.750% Senior Notes due April 18, 2054 (the “2054 Notes”), and (v) $1.0 billion aggregate principal amount of 5.900% Senior Notes due April 18, 2064 (the “2064 Notes” and together with the 2027 Notes, the 2030 Notes the 2034 Notes and the 2054 Notes, the “April 2024 Notes”).
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”).
Removed
We intend to fund the cash portion of the pending Double Eagle Acquisition through a combination of cash on hand, borrowings under our credit facility or proceeds from term loans and senior notes offerings.
Added
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.
Removed
Viper received total net proceeds for the Viper 2025 Equity Offering of approximately $1.2 billion after the underwriters’ discount and estimated transaction costs.
Added
The gain is included in the caption “Other income (expense), net” on the consolidated statements of operations for the year ended December 31, 2025. 43 Table of Contents 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.
Removed
The pending 2025 Drop Down is expected to close in the second quarter of 2025, subject to the approval by Viper’s stockholders, regulatory clearance and the satisfaction or waiver of other closing conditions. Viper intends to fund the cash consideration for the pending 2025 Drop Down with the net proceeds from the Viper 2025 Equity Offering discussed above.
Added
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.
Removed
The mineral and royalty interests owned by the Endeavor Subsidiaries being divested in the pending 2025 Drop Down represent approximately 22,847 net royalty acres located primarily in the Permian Basin. The Endeavor Subsidiaries being sold in the pending 2025 Drop Down were acquired by us in the recently completed Endeavor Acquisition. See Note 17— Subsequent Events in Item 8.
Added
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.
Removed
Financial Statements and Supplementary Data of this report for further discussion of the pending Double Eagle Acquisition, the Viper 2025 Equity Offering and the pending 2025 Drop Down. 2024 Diamondback Acquisitions and Divestitures Endeavor Acquisition On September 10, 2024, we completed the Endeavor Acquisition for consideration consisting of $7.3 billion in cash, subject to certain customary post-closing adjustments, and approximately 117.27 million shares of our common stock.
Added
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.
Removed
The Endeavor Acquisition included approximately 500,849 gross (361,927 net) acres, which are primarily located in the Permian Basin.
Added
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).
Removed
The cash consideration for the Endeavor Acquisition was funded through a combination of cash on hand, the net proceeds of the Company’s $5.5 billion April 2024 Senior Notes offering and $1.0 billion in borrowings under the Tranche A Loans (as defined and discussed below). See Note 5— Endeavor Energy Resources, LP Acquisition in Item 8.
Added
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.
Removed
TRP Energy, LLC Asset Exchange On December 20, 2024, we completed an exchange agreement with TRP Energy, LLC (“TRP”), in which we exchanged approximately 47,034 gross (35,673 net) acres located in the Delaware Basin and $325 million in cash, subject to customary post-closing adjustments, for certain of TRP’s assets consisting of approximately 21,582 gross (15,421 net) acres located in the Midland Basin (the “TRP Exchange”).
Added
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”).
Removed
The TRP Exchange was valued at approximately $1.4 billion. WTG Midstream Transaction On July 15, 2024, Remuda Midstream Holdings LLC, (the “WTG joint venture”) sold its WTG Midstream LLC subsidiary (the “WTG Midstream Transaction”), resulting in proceeds to us of 10.1 million common units of Energy Transfer LP and $190 million in cash, subject to customary closing adjustments.
Added
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. 44 Table of Contents 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.
Removed
At the closing of the WTG Midstream Transaction, the value attributable to us for the 10.1 million common units was approximately $135 million, of which we received approximately $81 million with the remaining $54 million held in escrow pursuant to an escrow agreement entered into by the WTG joint venture.
Added
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.
Removed
A gain of approximately $74 million was recognized for the WTG Transaction in the third quarter of 2024. 48 Table of Contents 2024 Viper Acquisitions Viper Tumbleweed Acquisitions On October 1, 2024, Viper and Viper LLC completed the Viper TWR Acquisition, for which the consideration consisted of approximately (i) $464 million in cash, (ii) 10.09 million Viper LLC units, including transaction costs and certain customary post-closing adjustments, (iii) the TWR Class B Option, and (iv) contingent cash consideration of up to $41 million payable in January of 2026.
Added
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.
Removed
The mineral and royalty interests acquired in the Viper TWR Acquisition represent approximately 3,067 net royalty acres located primarily in the Permian Basin.
Added
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.
Removed
On September 3, 2024 Viper and Viper LLC acquired all of the issued and outstanding equity interests in Tumbleweed-Q Royalties, LLC (i) the Viper Q Acquisition for a purchase price of approximately $114 million in cash, including transaction costs and certain customary post-closing adjustments, and a contingent cash consideration of up to $5 million payable in January of 2026, and (ii) MC TWR Royalties, LP and MC TWR Intermediate, LLC the Viper M Acquisition for a purchase price of approximately $76 million in cash, including transaction costs and certain customary post-closing adjustments, and a contingent cash consideration of up to $4 million payable in January of 2026.
Added
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.
Removed
Financial Statements and Supplementary Data of this report for further discussion of the TRP Exchange, the Viper Tumbleweed Acquisitions and the WTG Midstream Transaction. 2024 Capital Transactions Viper 2024 Equity Offering On September 13, 2024, Viper completed an underwritten public offering of approximately 11.5 million shares of its Class A common stock at a price to the public of $42.50 per share for total net proceeds to Viper of approximately $476 million (the “Viper 2024 Equity Offering”).
Added
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.
Removed
Term Loan Agreement In connection with the Endeavor Acquisition, we entered into a Term Loan Credit Agreement with Citibank, N.A. on February 29, 2024 (the “Term Loan Agreement”).
Added
The Viper 2025 Term Loan was repaid in full in February 2026.
Removed
The Term Loan Agreement provided the Company with the ability to borrow up to $1.5 billion, which was comprised of $1.0 billion of Tranche A Loans (the “Tranche A Loans”) and $500 million of Tranche B Loans (the “Tranche B Loans”). On August 2, 2024, we terminated our undrawn Tranche B Loans.
Added
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.
Removed
Initial borrowings of $1.0 billion under the Tranche A Loans were used to fund a portion of the cash consideration for the Endeavor Acquisition. Commodity Prices Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions.
Added
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.
Removed
During 2024, 2023 and 2022 the NYMEX WTI prices averaged $75.76, $77.60 and $94.33 per Bbl, respectively, and the NYMEX Henry Hub prices averaged $2.41, $2.66 and $6.54 per MMBtu, respectively. 49 Table of Contents For additional information around risks related to commodity prices, see Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk .
Added
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.
Removed
Outlook During 2024, we had total capital expenditures of $2.9 billion, which was consistent with our guidance presented in November 2024. In 2025, we expect production and capital expenditures to increase as a result of the Endeavor Acquisition the Viper Tumbleweed Acquisitions, and the pending Double Eagle Acquisition, if consummated.
Added
Based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine 45 Table of Contents 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.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

9 edited+0 added−3 removed5 unchanged
Biggest changeIn particular, the board’s audit committee is responsible, among other things, for risk management relating to legal and regulatory requirements, including cybersecurity, which plays an integral role in our risk management strategy and continues to be an area of increasing focus for our board, the audit committee and our management team.
Biggest changeIn particular, the board’s audit committee is responsible, among other things, for risk management relating to legal and regulatory requirements, including cybersecurity, which plays an integral role in our risk management strategy and continues to be an area of increasing focus for our board, the audit committee and our management team. 39 Table of Contents The audit committee of the board of directors receives quarterly updates from our Senior Vice President and Chief Information Officer on the status of our cybersecurity governance program, including as related to new or developing initiatives and any significant security incidents that may occur.
Risks from cybersecurity threats have not materially affected, and are not currently anticipated to materially affect, our Company, including our business strategy, results of operations or financial condition. See, however, Item 1A.
Risks from identified cybersecurity threats have not materially affected, and are not currently anticipated to materially affect, our Company, including our business strategy, results of operations or financial condition. See, however, Item 1A.
Our management team takes steps to remain informed about and monitor efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel; threat intelligence and other information obtained from governmental, public or private sources, including third-party consultants engaged by us; and alerts and reports produced by security tools deployed in our IT and OT environments.
Our management team takes steps to remain informed about and monitor efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel; threat intelligence and other information obtained from governmental, public or private sources, including third-party consultants engaged by us; alerts and reports produced by security tools deployed in our IT and OT environments; and through reporting by employees and service providers.
We have engaged third-party consultants to conduct penetration testing and risk assessments. Our cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity 42 Table of Contents Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration.
We have engaged third-party consultants to conduct penetration testing and risk assessments. Our cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration.
The Senior Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), CompTIASecurity+, and Department of Defense (DoD)-Cybersecurity General, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes.
The Senior Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), and CompTIASecurity+, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes.
In addition, our cybersecurity incident response team is responsible for responding to cybersecurity incidents in accordance with our Computer Security Incident Response Plan. Progress and developments in our cybersecurity governance program are communicated to members of the executive team.
In addition, our cybersecurity incident response team is responsible for responding to cybersecurity incidents and are guided by our Computer Security Incident Response Plan. Progress and developments in our cybersecurity governance program are communicated to members of the executive team.
Our cybersecurity risk management program includes: • risk assessments designed to help identify material cybersecurity risks to our critical systems, information, products, services, and our broader enterprise IT and operational technology, or OT, environments; • a security team principally responsible for managing (i) our cybersecurity risk assessment processes, (ii) our security controls, and (iii) our response to cybersecurity incidents; • the use of external service providers, where appropriate, to assess, test, train or otherwise assist with aspects of our security controls; • security tools deployed in the IT and OT environments for protection against and monitoring for suspicious activity; • cybersecurity awareness training of our employees, including incident response personnel and senior management; • cybersecurity tabletop exercises for members of our cybersecurity incident response team and legal department; • a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and • a third-party risk management process for service providers, suppliers and vendors.
Our cybersecurity risk management program includes: • risk assessments designed to help identify material cybersecurity risks to our critical systems, information, products, services, and our broader enterprise IT and operational technology, or OT, environments; • a security team principally responsible for managing (i) our cybersecurity risk assessment processes, (ii) our security controls, and (iii) our response to cybersecurity incidents; • the use of external service providers, where appropriate, to assess, test, train or otherwise assist with aspects of our security controls; • security tools deployed in the IT and OT environments for protection against and monitoring for suspicious activity; • cybersecurity awareness training of our employees, including incident response personnel and senior management; • cybersecurity tabletop exercises for members of our cybersecurity incident response team and legal department; • a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and • a third-party risk management process for service providers, which may include diligence, assessments and/or contractual requirements, depending on each service provider’s operational criticality and relative risk profile.
Risk Factors of this report for additional information regarding cybersecurity risks we face and their potential impact on our business strategy, results of operations and financial condition. 43 Table of Contents
Risk Factors of this report for additional information regarding cybersecurity risks we face and their potentially material impact on our business strategy, results of operations and financial condition.
Board members receive presentations on cybersecurity topics from the Senior Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies.
Board members also receive presentations on cybersecurity topics from the Senior Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies. Our cybersecurity governance program also includes processes to assess cybersecurity risks related to third-party service providers, suppliers and vendors.
Removed
The audit committee of the board of directors receives quarterly updates on the status of our cybersecurity governance program, including as related to new or developing initiatives and any security incidents that may occur.
Removed
Further, our code of business conduct and ethics expects all employees to safeguard our electronic communications systems and related technologies from theft, fraud, unauthorized access, alteration or other damage and requires them to report any cyberattacks or incidents, improper access or theft to our Chief Legal and Administrative Officer and the Senior Vice President and Chief Information Officer.
Removed
Our cybersecurity governance program also includes processes to assess cybersecurity risks related to third-party service providers, suppliers and vendors. Our vendor management process may include reviewing the cybersecurity practices of such provider, contractually imposing obligations on the provider, conducting security assessments and conducting periodic reassessments during their engagement.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

1 edited+0 added−0 removed3 unchanged
Biggest changeFor additional information regarding environmental matters, see Note 16— Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report.
Biggest changeFor additional information regarding environmental matters, see Note 15— Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

7 edited+9 added−2 removed1 unchanged
Biggest changeIssuer Repurchases of Equity Securities Our common stock repurchase activity for the three months ended December 31, 2024 was as follows: Period Total Number of Shares Purchased (1) Average Price Paid Per Share (2)(4) Total Number of Shares Purchased as Part of Publicly Announced Plan Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan (3)(4) ($ In millions, except per share amounts, shares in thousands) October 1, 2024 - October 31, 2024 951 $ 180.35 944 $ 2,907 November 1, 2024 - November 30, 2024 443 $ 177.79 443 $ 2,828 December 1, 2024 - December 31, 2024 939 $ 163.06 939 $ 2,675 Total 2,333 $ 172.90 2,326 (1) Includes 6,454 shares of common stock repurchased from executives in order to satisfy tax withholding requirements.
Biggest changeIssuer Purchases of Equity Securities Our common stock repurchase activity for the three months ended December 31, 2025 was as follows: Period Total Number of Shares Purchased (1)(2) Average Price Paid Per Share (3)(4) Total Number of Shares Purchased as Part of Publicly Announced Plan (2) Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan (4)(5) (In millions, except per share amounts, shares in thousands) October 1, 2025 - October 31, 2025 614 $ 143.21 611 $ 3,011 November 1, 2025 - November 30, 2025 2,275 $ 151.22 2,275 $ 2,667 December 1, 2025 - December 31, 2025 18 $ 144.98 18 $ 2,665 Total 2,907 $ 149.49 2,904 (1) Includes 3,301 shares of common stock repurchased from executives in order to satisfy tax withholding requirements.
Our board of directors’ determination with respect to any such dividends, whether base or variable, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.
Our board of directors’ determination with respect to any such dividends, whether base or variable, including the record date, the payment date and the actual amount of the dividend, will depend upon our outlook for commodity prices, our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.
Beginning in the first quarter of 2024, our board of directors has approved a reduction in our return of capital commitment to our shareholders to at least 50% (down from 75%) of our quarterly free cash flow through repurchases under our share repurchase program, base dividends and variable dividends to facilitate the repayment of indebtedness incurred in connection with the Endeavor Acquisition.
Dividend Policy In the first quarter of 2024, our board of directors approved a reduction in our return of capital commitment to our shareholders to at least 50% (down from 75%) of our quarterly Adjusted Free Cash Flow through repurchases under our share repurchase program, base dividends and variable dividends to accelerate the repayment of indebtedness incurred in connection with the Endeavor Acquisition and the Double Eagle Acquisition.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Listing and Holders of Record Our common stock is listed on the Nasdaq Global Select Market under the symbol “FANG”. There were 4,721 holders of record of our common stock on February 21, 2025.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Listing and Holders of Record Our common stock is listed on Nasdaq under the symbol “FANG”. There were 4,438 holders of record of our common stock on February 20, 2026.
All dollar amounts presented exclude such excise taxes, as applicable. 45 Table of Contents Stock Performance Graph The following performance graph includes a comparison of our cumulative total stockholder return over a five-year period with the cumulative total returns of the Standard & Poor’s 500 Stock Index, or the S&P 500 Index, and the SPDR S&P Oil & Gas Exploration and Production ETF, or XOP Index.
The performance graph includes a comparison of our cumulative total stockholder return over a five-year period with the cumulative total returns of the Standard & Poor’s 500 Stock Index, or the S&P 500, and the SPDR S&P Oil & Gas Exploration and Production ETF, or XOP.
The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time. (4) The Inflation Reduction Act of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022.
(5) The IRA, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022.
Such shares are cancelled and retired immediately upon repurchase. (2) The average price paid per share includes any commissions paid to repurchase stock. (3) On September 18, 2024, our board of directors approved an increase in our common stock repurchase program from $4.0 billion to $6.0 billion, excluding excise tax.
Financial Statements and Supplementary Data of this report. (3) The average price paid per share includes any commissions paid to repurchase stock. (4) In September 2021, our board of directors initiated our stock repurchase program.
Removed
Dividend Policy 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 the Company's outlook for commodity prices, liquidity, debt levels, capital resources, free cash flow and other factors.
Added
Recent Sales of Unregistered Securities During the three months ended December 31, 2025, the Company issued a total of 105,607 shares of common stock as partial consideration in connection with the acquisition of certain oil and gas leases from the sellers thereof in a private transaction exempt from registration pursuant to Section 4(a)(2) of the Securities Act.
Removed
The graph assumes an investment of $100 on December 31, 2019, and that all dividends were reinvested. As of December 31, Calculated Values 2019 2020 2021 2022 2023 2024 Diamondback Energy, Inc. $100.00 $54.00 $122.81 $166.41 $199.06 $219.68 S&P 500 $100.00 $118.39 $152.34 $124.73 $157.48 $196.85 XOP $100.00 $63.69 $106.21 $154.35 $159.83 $158.18
Added
Such shares are cancelled and retired immediately upon repurchase. (2) Includes 2.0 million shares repurchased from SGF FANG Holdings, LP (“SGF”) during the fourth quarter of 2025 pursuant to a privately negotiated letter agreement dated November 28, 2025. For further discussion on the repurchase from SGF, see Note 7— Related Party Transactions in Item 8.
Added
On July 31, 2025, our board of directors approved a $2.0 billion increase in our common stock repurchase program from $6.0 billion to $8.0 billion, excluding excise tax. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.
Added
All dollar amounts presented exclude such excise taxes, as applicable. 41 Table of Contents Stock Performance Graph The following performance graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC, nor should such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing.
Added
The performance graph and information are included for historical comparative purposes only and should not be considered indicative of future stock performance.
Added
The graph assumes an investment of $100 on December 31, 2020, and that all dividends were reinvested.
Added
As of December 31, Calculated Values: 2020 2021 2022 2023 2024 2025 Diamondback Energy, Inc. $100.00 $227.44 $308.19 $368.65 $406.86 $383.98 S&P 500 $100.00 $128.68 $105.36 $133.03 $166.28 $195.98 XOP $100.00 $166.76 $242.36 $250.96 $248.37 $243.04 ITEM 6. [RESERVED] 42 Table of Contents ITEM 7.
Added
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.
Added
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 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

206 edited+66 added−120 removed228 unchanged
Biggest changeThe following is a summary of the principal risks that could adversely affect our business, operations and financial results: Risks Related to the Oil and Natural Gas Industry and Our Business • Market conditions and particularly volatility in prices for oil and natural gas may adversely affect our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves. • Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty credit risk. • The IRA and other risks relating to climate change could accelerate the transition to a low carbon economy and could impose new costs on our operations that may have a material and adverse effect on us. • Climate change-related regulations, policies and initiatives may have other adverse effects, such as a greater potential for governmental investigations or litigation. • We may be unable to obtain needed capital or financing on satisfactory terms or at all to fund our acquisitions or development activities, which could lead to a loss of properties and a decline in our oil and natural gas reserves and future production. • Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings, and title defects in the properties in which we invest may lead to losses. • Our identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. • If production from our Permian Basin acreage decreases, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which may adversely affect our operations. • The inability of one or more of our customers to meet their obligations, or loss of one or more of our significant purchasers, may adversely affect our financial results. • Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value. • Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. • We are vulnerable to risks associated with our primary operations concentrated in a single geographic area. • If transportation or other facilities, certain of which we do not control, or rigs, equipment, raw materials, oil services or personnel are unavailable, our operations could be interrupted and our revenues reduced. • Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive and may impose restrictions on our operations. • U.S. tax legislation, including recently adopted IRA, may negatively affect our business, results of operations, financial condition and cash flow. • Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations. • We rely on a few key employees whose absence or loss could adversely affect our business. • A terrorist attack or armed conflict could harm our business and could adversely affect our business. • A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss. • Following the closing of the Endeavor Acquisition, the Endeavor equityholders have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders.
Biggest changeIf any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline. 21 Table of Contents The following is a summary of the principal risks that could adversely affect our business, operations and financial results: Risks Related to the Oil and Natural Gas Industry and Our Business • Geopolitics and market conditions, and particularly volatility in prices for oil and natural gas, may adversely affect our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves. • Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty credit risk. • Changes in U.S. trade policy and the impact of tariffs may have a material adverse impact on our business and results of operations. • Risks relating to the transition to a low carbon economy could impose new costs on our operations that may have a material and adverse effect on us. • Changing political and social perspectives on climate change and other environmental, social and governance factors may create risks and uncertainties impacting our business. • Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks. • Our success depends on developing our existing leasehold acreage and finding, developing or acquiring additional reserves. • We may be unable to obtain needed capital or financing on satisfactory terms or at all to fund our acquisitions, exploration or development activities. • Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings. • Our identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. • We may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contracts. • The loss of one or more of our customers or their inability to meet their obligations may adversely affect our financial results. • Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value. • Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. • The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. • We are vulnerable to risks associated with our primary operations concentrated in a single geographic area. • If transportation or other facilities, certain of which we do not control, or rigs, equipment, raw materials, supplies, oilfield services or personnel become unavailable or too costly, our operations could be interrupted and our revenues reduced. • Restrictions on our ability to obtain water and dispose of produced water, and additional monitoring and reporting requirements related to existing and new produced water disposal wells in the Permian Basin could adversely impact our business, results of operations and financial condition. • Our planned exploratory drilling in existing or emerging shale plays is subject to risks associated with drilling and completion techniques. • Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive. • U.S. tax legislation may negatively affect our business, results of operations, financial condition and cash flow. • We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets. • Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits. • We may not be able to keep pace with technological developments in our industry. • Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems.
To the extent that the prices of oil, natural gas liquids and natural gas remain at current levels or decline further, we may not be able to economically hedge additional future production at the same level as our current commodity price derivatives, and our results of operations and financial condition may be negatively impacted.
To the extent that the prices of oil, natural gas and natural gas liquids remain at current levels or decline further, we may not be able to economically hedge additional future production at the same level as our current commodity price derivatives, and our results of operations and financial condition may be negatively impacted.
We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells.
We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties, and (iii) an extension of the amortization period for certain geological and geophysical expenditures.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties, and (iii) an extension of the amortization period for certain geological and geophysical expenditures.
The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” or the CWA, the Safe Drinking Water Act, the Oil Pollution Act, or the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters.
The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” or the CWA, the Safe Drinking Water Act, the Oil Pollution Act of 1990, or the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters.
Additionally, on March 8, 2024, the EPA published a final rule to expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations.
On March 8, 2024, the EPA published a final rule to expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations.
We also involve employees from all operational levels in our safety program to provide input and suggested improvements to the overall safety program, recommend preventative measures based on reviewing vehicle and personnel incidents, safety and environmental audits at operational locations and participate in the audit and oversight of the Diamondback Hazard Communication Program.
We also involve employees from all operational levels in our safety program to provide input and suggested improvements to the overall safety program, recommend preventative measures based on reviewing vehicle and personnel incidents, perform safety and environmental audits at operational locations and participate in the audit and oversight of the Diamondback Hazard Communication Program.
Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing.
Furthermore, certain of the techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing.
These alternate forms of energy include electricity, coal and fuel oils. Oil and Natural Gas Leases The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises.
These alternate forms of energy include electricity, coal, fuel oils and nuclear energy. Oil and Natural Gas Leases The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises.
Marketing and Customers We typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the years ended December 31, 2024 and 2023, four purchasers each accounted for more than 10% of our revenue.
Marketing and Customers We typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the years ended December 31, 2025, 2024 and 2023 four purchasers each accounted for more than 10% of our revenue.
Risks Related to the Oil and Natural Gas Industry and Our Business Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
Risks Related to the Oil and Natural Gas Industry and Our Business Geopolitics and market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities.
Additionally, our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities.
The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from 19 Table of Contents $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $272,926 and $2,729,245, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements.
The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $272,926 and $2,729,245, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements.
The Pipeline Safety and Job Creation Act, enacted in 2011, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, also known as the PIPES Act, enacted in 2016, amended the HLPSA and increased safety regulation.
The Pipeline Safety and Job Creation Act, enacted in 2011, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020, also known as the PIPES Act, amended the HLPSA and increased safety regulation.
Undeveloped Acreage Expirations As of December 31, 2024, the following gross and net undeveloped acres are set to expire over the next five years based on their contractual lease maturities unless (i) production is established within the spacing units covering the acreage or (ii) the lease is renewed or extended under continuous drilling provisions prior to the contractual expiration dates.
Undeveloped Acreage Expirations As of December 31, 2025, the following gross and net undeveloped acres are set to expire over the next five years based on their contractual lease maturities unless (i) production is established within the spacing units covering the acreage or (ii) the lease is renewed or extended under continuous drilling provisions prior to the contractual expiration dates.
In addition to potentially reducing demand for our oil and natural gas and potentially reducing the availability of oilfield services and midstream and downstream customers, any further regulatory or other climate change incentives, to the extent they continue, may create reputational risks associated with the exploration for, and production of, hydrocarbons, which may adversely affect the availability and cost to us of capital.
In addition to potentially reducing demand for our oil and natural gas and potentially reducing the availability of oilfield services and midstream and downstream customers, further regulatory or other climate change incentives, to the extent they continue, may create investment and reputational risks associated with the exploration for, and production of, hydrocarbons, which may adversely affect the availability and cost to us of capital.
Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. In addition to the geographic concentration of our producing properties described above, as of December 31, 2024, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin.
Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. In addition to the geographic concentration of our producing properties described above, as of December 31, 2025, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin.
Item 7. Management Discussion and Analysis—Critical Accounting Estimates of this report. As a result, we maintain an internal staff of petroleum engineers and geoscience professionals that have an internal control process to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves.
Item 7. Management’s Discussion and Analysis—Critical Accounting Estimates of this report. As a result, we maintain an internal staff of petroleum engineers and geoscience professionals that have an internal control process to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as the oil and natural gas industry in general.
Changes in environmental laws and regulations occur frequently, and may result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements that could materially and adversely affect our operations and financial position, as well as the oil and natural gas industry in general.
We use commodity price derivatives, which have historically included swaps, basis swaps, swaptions, roll hedges, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil, natural gas liquids and natural gas sales. Currently, we have hedged a portion of our estimated 2025 and 2026 production.
We use commodity price derivatives, which have historically included swaps, basis swaps, swaptions, roll hedges, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil, natural gas and natural gas liquids sales. Currently, we have hedged a portion of our estimated 2026 and 2027 production.
Also, on November 15, 2021, PHMSA published a final rule extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements for certain gas gathering pipelines with large diameters and high operating pressures, and, on August 24, 2022, PHMSA published a final rule strengthening integrity management requirements for onshore gas transmission lines, bolstering corrosion control standards and repair criteria, and imposing new requirements for inspections after extreme weather events.
Also, on November 15, 2021, PHMSA published a final rule extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements for certain gas gathering pipelines with large diameters and high operating pressures, and, on August 24, 2022, PHMSA published a final rule strengthening integrity management requirements for onshore gas 18 Table of Contents transmission lines, bolstering corrosion control standards and repair criteria, and imposing new requirements for inspections after extreme weather events.
If any of these developments reduce the desirability of participating in the oilfield services, midstream or downstream portions of the oil and gas industry, then these developments may also reduce the availability to us of necessary third-party services and facilities that we rely on, which could increase our operational costs and adversely affect our ability to explore for, produce, transport and process oil and natural gas and successfully carry out our business and financial strategy.
If any of these developments reduce the desirability of participating in the oilfield services, midstream or downstream portions of the oil and gas industry, then these developments may also reduce the availability to us of necessary third-party services and facilities that we rely on, which could increase our operational costs and adversely affect 24 Table of Contents our ability to explore for, produce, transport and process oil and natural gas and successfully carry out our business and financial strategy.
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.
Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal 13 Table of Contents injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal 12 Table of Contents injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flow.
In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders for any violations could have an adverse impact on our business, financial condition, results of operation and cash flow.
For example, a significant hurricane or similar weather event could damage refining and other oil and natural gas-related facilities on the Gulf Coast of Texas and Louisiana, which (if significant enough) could limit the availability of gathering and transportation facilities across Texas and could then cause production in the Permian Basin (including potentially our production) to be curtailed or shut in or (in the case of natural gas) flared.
For example, a significant hurricane or similar weather event could damage refining and other oil and natural gas-related facilities on the Gulf Coast of Texas and Louisiana, which (if significant enough) could limit the availability of gathering and transportation facilities across Texas and could then cause production in the Permian Basin (including potentially our 29 Table of Contents production) to be curtailed or shut in or (in the case of natural gas) flared.
Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. Waste Handling.
Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.
Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, unusual or unexpected geological formations, title problems, facility or equipment malfunctions, unexpected operational events, inclement weather, environmental and other regulatory requirements and approvals, oil and natural gas prices, costs, drilling results and the availability of water.
Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, unusual or unexpected geological 27 Table of Contents formations, title problems, facility or equipment malfunctions, unexpected operational events, inclement weather, environmental and other regulatory requirements and approvals, oil and natural gas prices, costs, drilling results and the availability of water.
The Endeavor equityholders’ level of ownership and influence may make some transactions (such as those involving mergers, material share issuances or changes in control) more difficult or impossible, which in turn could adversely 38 Table of Contents affect the market price of our shares of common stock or prevent our shareholders from realizing a premium over the market price for their shares of our common stock.
The Endeavor equityholders’ level of ownership and influence may make some transactions (such as those involving mergers, material share issuances or changes in control) more difficult or impossible, which in turn could adversely affect the market price of our shares of common stock or prevent our shareholders from realizing a premium over the market price for their shares of our common stock.
For example, on August 16, 2012, the EPA published final regulations under the federal CAA that establish new emission controls for oil and natural gas production and processing operations, which are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry.
For example, on August 16, 2012, the EPA published final regulations under the federal CAA that establish new emission controls for oil and natural gas production and processing operations, which are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source if they are under common control for air-quality permitting purposes applicable to the oil and natural gas industry.
The amount of the limitation is generally equal to the value of the corporation’s stock immediately prior to the ownership change multiplied by an interest rate, referred 41 Table of Contents to as the long-term tax-exempt rate, periodically promulgated by the IRS.
The amount of the limitation is generally equal to the value of the corporation’s stock immediately prior to the ownership change multiplied by an interest rate, referred to as the long-term 37 Table of Contents tax-exempt rate, periodically promulgated by the IRS.
Training and Development We support employees in pursuing training opportunities to expand their professional skills. Our internal course offerings in 2024 included a wide array of topics in addition to extensive safety and other compliance training sessions.
Training and Development We support employees in pursuing training opportunities to expand their professional skills. Our internal course offerings in 2025 included a wide array of topics in addition to extensive safety and other compliance training sessions.
Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. Reports filed or furnished with the SEC are also made available on its website at www.sec.gov. 22 Table of Contents ITEM 1A.
Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. Reports filed or furnished with the SEC are also made available on its website at www.sec.gov. ITEM 1A.
Our financial position and results of operations may also fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. 28 Table of Contents Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our financial position and results of operations may also fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations. Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations. 31 Table of Contents Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
We may be limited in our ability to repurchase shares of our common stock by various governmental laws, rules and regulations which prevent us from purchasing our common stock during periods when we are in possession of material non-public information. Through December 31, 2024, approximately $3.3 billion has been repurchased through the repurchase program.
We may be limited in our ability to repurchase shares of our common stock by various governmental laws, rules and regulations which prevent us from purchasing our common stock during periods when we are in possession of material non-public information. Through December 31, 2025, approximately $5.3 billion has been repurchased through the repurchase program.
In some instances, forced pooling or unitization may be implemented by third 18 Table of Contents parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production.
In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production.
The IRA amends the CAA to impose a fee on the emission of methane that exceeds an applicable waste emissions threshold from sources required to report their greenhouse gas emissions to the EPA, including those sources in offshore and onshore petroleum and natural gas production and gathering and boosting source categories.
The IRA amends the CAA to impose a “waste emissions charge” on the emission of methane that exceeds an applicable waste emissions threshold from sources required to report their greenhouse gas emissions to the EPA, including those sources in offshore and onshore petroleum and natural gas production and gathering and boosting source categories.
The effect of these regulations 20 Table of Contents may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws.
The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws.
Also, in 2021, the Texas Legislature directed the Texas Railroad Commission to adopt rules encouraging fluid oil and gas waste recycling. On January 3, 2025, the Commission published final amendments to its water protection rules to, among other things, encourage waste recycling. The revised rules will go into effect on July 1, 2025.
Also, in 2021, the Texas Legislature directed the Texas Railroad Commission to adopt rules encouraging fluid oil and gas waste recycling. On January 3, 2025, the Commission published final amendments to its water protection rules to, among other things, encourage waste recycling. The revised rules went into effect on July 1, 2025.
We are requiring our operational employees and independent contractors and their employees to go through orientation and training aligned with the International Association of Oil and Gas Producers Life Saving Rules, a program that also meets the operational safety requirements adopted by the American Petroleum Institute.
We require our operational employees and independent contractors and their employees to go through orientation and training aligned with the International Association of Oil and Gas Producers Life Saving Rules, a program that also meets the operational safety requirements adopted by the American Petroleum Institute.
If endangered species, such as the recently listed lesser prairie chicken or dunes sagebrush lizard, are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required.
If endangered species, such as the lesser prairie chicken or dunes sagebrush lizard, are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed, or expensive mitigation could be required.
For 2024, our reserve auditor’s estimates of our proved reserves did not materially differ from our estimates by more than the established audit tolerance guidelines of ten percent.
For 2025, our reserve auditor’s estimates of our proved reserves did not materially differ from our estimates by more than the established audit tolerance guidelines of ten percent.
While these commodity price derivatives are intended to mitigate risk from commodity price volatility, we may be prevented from fully realizing the benefits of increases in the prices of oil, natural gas liquids and natural gas above the price levels of the commodity price derivatives used to manage price risk.
While these commodity price derivatives are intended to mitigate risk from 23 Table of Contents commodity price volatility, we may be prevented from fully realizing the benefits of increases in the prices of oil, natural gas and natural gas liquids above the price levels of the commodity price derivatives used to manage price risk.
Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.
Among other things, these rules require companies seeking permits 30 Table of Contents for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC.
The availability, terms and cost of transportation of oil and natural gas significantly affect its marketability and sale. The interstate transportation and sale for resale of natural gas, and the interstate transportation of oil, is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC.
For additional information regarding our outstanding derivative contracts as of December 31, 2024, see Note 13— Derivatives in Item 8. Financial Statements and Supplementary Data, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk —Commodity Price Risk of this report.
For additional information regarding our outstanding derivative contracts as of December 31, 2025, see Note 12— Derivatives in Item 8. Financial Statements and Supplementary Data, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk —Commodity Price Risk of this report.
In addition, as of December 31, 2024, we have identified approximately 1,657 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours.
In addition, as of December 31, 2025, we have identified approximately 1,901 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours.
As part of the audit process, we provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs.
As part of the audit process, we provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and natural gas production, commodity prices and operating and development costs.
A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history.
A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, and are less reliable than estimates based on a lengthy production history.
Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts. (2) Average production costs is comprised of lease operating expenses and gathering, processing and transportation expense.
Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts. 8 Table of Contents (2) Average production costs is comprised of lease operating expenses and gathering, processing and transportation expense.
No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, 34 Table of Contents what the specific provisions or the effective date of any such legislation would be.
No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be.
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden.
Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden.
To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense.
To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, 28 Table of Contents exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense.
If we do not, or are perceived to not, adapt or comply with investor or stakeholder expectations and standards on ESG matters, we may suffer from reputational damage and our business, financial condition 26 Table of Contents and results of operations could be materially and adversely affected.
If we do not, or are perceived to not, adapt or comply with certain investor or stakeholder expectations and standards on ESG matters, we may suffer from reputational damage and our business, financial condition and results of operations could be materially and adversely affected.
As of December 31, 2024, only 1,381 of our gross identified economic potential horizontal drilling locations in which we have a working interest were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy.
As of December 31, 2025, only 1,351 of our gross identified economic potential horizontal drilling locations in which we have a working interest were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy.
The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders.
The existence of some provisions in our certificate of incorporation and bylaws could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders.
Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Ryder Scott performed an independent analysis during its audit of our estimated reserves for 2024 and any differences were reviewed with our Executive Vice President and Chief Engineer.
Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, commodity prices and operating and development costs. Ryder Scott performed an independent analysis during its audit of our estimated reserves for 2025 and any differences were reviewed with our Executive Vice President and Chief Engineer.
These incentives and regulations could accelerate the transition of the economy away from the use of fossil fuels toward lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell and adversely impact our business.
These incentives and regulations, if implemented, may encourage the transition of the economy away from the use of fossil fuels toward lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell and adversely impact our business.
If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business. We are subject to cybersecurity risks.
If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business.
This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in; (i) the enactment of climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures; (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); (iii) increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and (iv) development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.
Such views, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in: (i) the enactment of new or evolving climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures; (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in battery technology); (iii) variability in demand from consumers and industry for energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and (iv) development of, and variable demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.
States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have undertaken responsibility to enforce the federal standards.
States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have been certified by PHMSA to assume responsibility to enforce the federal standards.
The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state.
The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the 13 Table of Contents EPA or the state.
The Executive Vice President and Chief Engineer is a petroleum engineer with over 21 years of reservoir and operations experience and our geoscience staff has an average of approximately 16 years of industry experience per person.
The Executive Vice President and Chief Engineer is a petroleum engineer with over 22 years of reservoir and operations experience and our geoscience staff has an average of approximately 17 years of industry experience per person.
As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock. ITEM 1B. UNRESOLVED STAFF COMMENTS None.
As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.
Following the closing of the Endeavor Acquisition, the Endeavor equityholders have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders. As of December 31, 2024, Endeavor’s equityholders held approximately 36% of our common stock.
Following the closing of the Endeavor Acquisition, the Endeavor equityholders have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders. As of December 31, 2025, Endeavor’s equityholders held approximately 35.8% of our common stock.
(“QEP”) and Rattler. As a result of ownership changes for Diamondback Energy, Inc., QEP and Rattler, which occurred in connection with the acquisition of QEP and the Rattler Merger, our NOLs and other carryforwards, including those acquired from QEP and Rattler, are subject to an annual limitation under Section 382 of the Code.
As a result of ownership changes for Diamondback Energy, Inc., QEP and Rattler, which occurred in connection with the acquisition of QEP and the Company’s merger with Rattler in 2022, our NOLs and other carryforwards, including those acquired from QEP and Rattler, are subject to an annual limitation under Sections 382 and 383 of the Code.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2025 could exceed our 27 Table of Contents capital expenditure budget.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2026 could exceed our capital expenditure budget.
The internal control procedures utilized in the preparation of our proved reserve estimates are intended to ensure reliability of reserve estimations, and include the following: • review and verification of historical production data, which is based on actual production as reported by us; • preparation of reserve estimates by the primary reserve engineers or under their direct supervision; • review by the primary reserve engineers of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions; • review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database; • direct reporting responsibilities by our Executive Vice President and Chief Engineer to our Executive Vice President—Operations; • prior to finalizing the reserve report, a review of our preliminary proved reserve estimates by our Chief Executive Officer, President and Chief Financial Officer, Executive Vice President and Chief Operating Officer, Executive Vice President and Chief Engineer and our primary reserves engineers takes place on an annual basis; • review of our proved reserve estimates by our Audit Committee with our executive team and Ryder Scott on an annual basis; • verification of property ownership by our land department; and • no employee’s compensation is tied to the amount of reserves booked. 7 Table of Contents For estimates and further discussion of our proved developed and proved undeveloped reserves, see Note 19— Supplemental Information on Oil and Natural Gas Operations in Item 8.
The internal control procedures utilized in the preparation of our proved reserve estimates are intended to ensure reliability of reserve estimations and include the following: • review and verification of historical production data, which is based on actual production as reported by us; • preparation of reserve estimates by the primary reserve engineers or under their direct supervision; • review by the primary reserve engineers of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions; 6 Table of Contents • review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database; • direct reporting responsibilities by our Executive Vice President and Chief Engineer to our Executive Vice President and Chief Operating Officer; • prior to finalizing the reserve report, a review of our preliminary proved reserve estimates by our Chief Executive Officer, Executive Vice President and Chief Financial Officer, Executive Vice President and Chief Operating Officer, Executive Vice President and Chief Engineer and our primary reserves engineers takes place on an annual basis; • review of our proved reserve estimates by our Audit Committee with our executive team and Ryder Scott on an annual basis; • verification of property ownership by our land department; and • no employee’s compensation is tied to the amount of reserves booked.
An ownership change would establish an annual limitation on the amount of a corporation’s pre-change NOLs or tax credits that could be utilized to offset taxable income in any future taxable year.
An ownership change would establish an annual limitation on the amount of a corporation’s pre-change NOLs, tax credits and capital loss carryforwards that could be utilized to offset taxable income in any future taxable year.
The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The scope of waters regulated under the CWA has fluctuated in recent years. On January 18, 2023, the EPA and the U.S.
The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The scope of waters regulated under the CWA has fluctuated in recent years due to notable rulemaking efforts and judicial challenges. On January 18, 2023, the EPA and the U.S.
Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks. We have developed, and will continue to develop, targets related to our environmental, social and governance (“ESG”) initiatives, including our emissions reduction targets and strategy.
Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks. We have developed, and will continue to develop, targets related to our ESG initiatives, including our emissions reduction targets and strategy.
Our gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements. In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers.
Our gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with applicable pipeline safety and pollution control requirements. In addition to PHMSA regulation, we are subject to the requirements of OSHA and comparable state statutes, whose purpose is to protect the health and safety of workers.
As an exploration and production company, we rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or externally hosted hardware and software platforms, to (i) estimate our oil and natural gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, transportation, pipelines and other related activities and (iv) communicate with our employees and vendors, suppliers and other third parties.
We rely extensively on information technology systems and infrastructure, including but not limited to, data hosting platforms, real-time data acquisition systems, internally developed and third-party software, cloud services and other internally or externally hosted hardware and software platforms (collectively, “IT Systems”) for operational and other purposes, such as to (i) estimate our oil and natural gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, transportation, pipelines and other related activities, and (iv) communicate with our employees and vendors, suppliers and other third parties.
Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations.
We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations.
Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including the domestic and foreign supply of oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports; political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia; the potential impact of the war in Ukraine, the Israel-Hamas War and other conflicts in the Middle East on the global energy markets and macroeconomic conditions; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; the ability of members of the OPEC+ to agree to and maintain oil price and production controls; speculative trading in crude oil and natural gas derivative contracts; the level of consumer product demand; extreme weather conditions and other natural disasters; risks associated with operating drilling rigs; technological advances affecting energy consumption; the price and availability of alternative fuels; domestic and foreign governmental regulations and taxes, including the new administration’s energy and environmental policies; global or national health concerns, including the outbreak of pandemic or contagious disease; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and overall domestic and global economic conditions.
Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including the domestic and foreign supply of oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports; political and economic conditions in oil producing countries; regional conflicts and political instability; the continued threat of terrorism, including attacks targeting oil and gas facilities and the impact of military and other action; the ability of members of OPEC+ to agree to and maintain oil price and production controls; speculative trading in crude oil and natural gas derivative contracts; the level of consumer product demand; extreme weather conditions and other natural disasters; risks associated with operating drilling rigs; technological advances affecting energy consumption; the price and availability of alternative fuels; domestic and foreign governmental regulations and taxes; global or national health concerns, including the outbreak of pandemic or contagious disease; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and overall domestic and global economic conditions.
The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil reserves. The present value of future net cash flows from our proved reserves, or standardized measure may not represent the current market value of our estimated proved oil reserves.
The present value of future net cash flows from our proved reserves or standardized measure may not represent the current market value of our estimated proved reserves.
Since inception, we have had no employee work-related fatalities. Our employee OSHA recordable cases, comprising work-related injuries and illnesses that require medical treatment beyond first aid, totaled 11 in 2024, up from three in 2023.
Since inception, we have had no employee work-related fatalities. Our employee OSHA recordable cases, comprising work-related injuries and illnesses that require medical treatment beyond first aid, totaled 11 in 2025, consistent with 11 in 2024.
Financial Statements and Supplementary Data of this report. Potential Drilling Locations We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities.
Potential Drilling Locations We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities.
At an assumed price of approximately $50.00 per Bbl WTI, we currently have approximately 9,188 gross (7,130 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data.
At an assumed price of approximately $50.00 per Bbl WTI, we currently have approximately 8,854 gross (6,541 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeNet cash used in financing activities for the year ended December 31, 2023 was primarily attributable to (i) $1.4 billion of dividends paid to stockholders, (ii) $935 million of repurchases as part of the Diamondback and Viper share repurchase programs, (iii) $134 million paid for the retirement of outstanding principal on certain senior notes, and (iv) $129 million in distributions to non-controlling interest.
Biggest changeFinancing 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.
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, free cash flow and other factors.
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.
Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers as of December 31, 2024, 2023 and 2022.
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.
However, any cash derivative gain or loss may be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. For additional information on our open commodity derivative instruments at December 31, 2024, see Note 13— Derivatives in Item 8. Financial Statements and Supplementary Data of this report.
However, any cash derivative gain or loss may be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. For additional information on our open commodity derivative instruments at December 31, 2025, see Note 12— Derivatives in Item 8. Financial Statements and Supplementary Data of this report.
Positive evidence may include forecasts of future taxable income, assessment of future business assumptions and any applicable tax planning strategies available to the Company. Negative evidence may include losses in recent years, if any, or the projection of losses in future periods.
Positive evidence may include forecasts of future taxable income, assessment of future business assumptions and any applicable tax planning strategies available to the 58 Table of Contents Company. Negative evidence may include losses in recent years, if any, or the projection of losses in future periods.
These cash outflows were partially offset by proceeds received from the divestitures of various oil and gas properties and other assets, which are discussed further in Note 4— Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report.
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.
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 (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards.
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.
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 and Note 5— Endeavor Energy Resources, LP Acquisition in Item 8.
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.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Commodity Price Risk Our major market risk exposure in our exploration and production business is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production.
Commodity Price Risk Our major market risk exposure in our exploration and production business is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production.
Business and Properties —Oil and Natural Gas Data—Wells Drilled and Completed in 2024 of this report.
Business and Properties —Oil and Natural Gas Data—Wells Drilled and Completed in 2025 of this report.
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 $2.0 billion, or 16% of the change in the standardized measure of our total reserves from December 31, 2023 to December 31, 2024.
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.
We use derivatives, including swaps, basis swaps, roll swaps, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil and natural gas sales. At December 31, 2024, we had a net asset of $145 million related to our commodity price risk derivatives.
We use derivatives, including swaps, basis swaps, roll swaps, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil and natural gas sales. At December 31, 2025, we had a net asset derivative position of $198 million related to our commodity price risk derivatives.
Counterparty and Customer Credit Risk Our principal exposures to credit risk are due to the concentration of receivables from the sale of our oil and natural gas production (approximately $1.4 billion at December 31, 2024), and to a lesser extent, receivables resulting from joint interest receivables (approximately $188 million at December 31, 2024).
Counterparty and Customer Credit Risk Our principal exposures to credit risk are due to the concentration of receivables from the sale of our oil and natural gas production (approximately $1.1 billion at December 31, 2025), and to a lesser extent, receivables resulting from joint interest and other receivables (approximately $258 million at December 31, 2025).
At December 31, 2024, we have interest rate swap agreements for a notional amount of $900 million to manage the impact of changes to the fair value of our fixed rate senior notes due to changes in market interest rates through December 2029.
At December 31, 2025, we have interest rate swap agreements for an aggregate $300 million notional amount to manage the impact of changes to the fair value of our fixed rate senior notes due to changes in market interest rates through December 2029.
For additional information on our interest rate swaps, see Note 13— Derivatives in Item 8. Financial Statements and Supplementary Data of this report. 65 Table of Contents
For additional information on our interest rate swaps, see Note 12— Derivatives in Item 8. Financial Statements and Supplementary Data of this report.
The positive evidence assessed included recent cumulative income due in part to commodity prices remaining consistently high, 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, 2024, Viper had a deferred tax asset of $185 million.
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.
We pay an average variable rate of interest for these swaps based on three-month SOFR plus 2.1865% and receive a fixed interest rate of 3.50% from our counterparties. At December 31, 2024, our receive-fixed, pay-variable interest rate swaps were in a net liability position of $124 million, and the weighted average variable rate was 6.43%.
We pay an average variable rate of interest for these swaps based on 3-month SOFR plus 2.1865% and receive a fixed interest rate of 3.50% from our counterparties. At December 31, 2025, our receive-fixed, pay-variable interest rate swaps were in a liability position of $27 million, and the weighted average variable rate was 5.79%.
We did not record any impairment on our unevaluated properties during the year ended December 31, 2024, but any such future impairment could potentially be material to our consolidated financial statements. 62 Table of Contents Business Combinations We account for business combinations in which it has been determined we are the acquirer using the acquisition method of accounting.
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.
We expect to make aggregate payments of approximately $442 million for these commitments during 2025. See Note 7— Asset Retirement Obligations and Note 16— 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 expect to make aggregate payments of approximately $586 million for these commitments during 2026. See Note 6— Asset Retirement Obligatio ns 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.
These cash inflows were partially offset by (i) $1.6 billion of dividends paid to stockholders, (ii) $959 million of repurchases as part of the share repurchase program, (iii) $227 million in dividends to non-controlling interest, (iv) $99 million of debt issuance costs primarily associated with the April 2024 Notes, Term Loan Agreement and Bridge Facility, and (vi) $39 million in cash paid for tax withholdings on vested employee stock awards.
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 53 Table of Contents 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.
Cash Flow Our cash flows for the years ended December 31, 2024 and 2023 are presented below: Year Ended December 31, 2024 2023 (In millions) Net cash provided by (used in) operating activities $ 6,413 $ 5,920 Net cash provided by (used in) investing activities (11,221) (3,323) Net cash provided by (used in) financing activities 4,387 (2,176) Net change in cash $ (421) $ 421 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.
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) 52 Table of Contents 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.
Utilizing actual contractual volumes under our commodity price derivatives as of December 31, 2024, a 10% increase in forward curves associated with the underlying commodity would have decreased the net asset position by $15 million to $130 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset derivative position by $36 million to $181 million.
Utilizing actual derivative contractual volumes under our commodity price derivatives as of December 31, 2025, a 10% increase in forward curves associated with the underlying commodity would have decreased the net asset position by $3 million to $195 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset position by $60 million to $258 59 Table of Contents million.
At December 31, 2024, the applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate, and from 1.125% to 2.000% per annum in the case of Adjusted Term SOFR, in each case based on the pricing level for both our revolving credit facilities and Tranche A Loans.
At December 31, 2025, the applicable margin ranges from 0.000% to 0.750% per annum in the case of the alternate base rate and from 1.000% to 1.750% per annum in the case of term SOFR, in each case based on the pricing level for our revolving credit facility.
Additionally, we expect to incur future cash interest costs on these senior notes of approximately $612 million in 2025, $1.2 billion cumulatively in the years from 2026 through 2027, $1.0 billion cumulatively in the years from 2028 and 2029, and $7.1 billion cumulatively between 2030 and 2064.
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.
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.
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.
The increase in operating cash flows for the year ended December 31, 2024 compared to the same period in 2023 primarily resulted from (i) an increase of $1.8 billion in total revenue, excluding sales of purchased oil, (ii) an additional $138 million in interest income, and (iii) a reduction of $59 million in cash paid on settlements of derivatives.
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.
Other Contractual Obligations and Commitments At December 31, 2024, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $2.8 billion, (ii) electrical power purchase commitments totaling $365 million (iii) asset retirement obligations totaling $592 million, (iv) electric fracturing fleet and related power generation services commitments totaling $199 million and (v) minimum purchase commitments for quantities of sand used in our drilling operations totaling $66 million.
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.
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, 2024 2023 (In millions) Drilling, completions and non-operated additions to oil and natural gas properties $ 2,632 $ 2,429 Infrastructure additions to oil and natural gas properties 221 153 Additions to midstream assets 14 119 Total $ 2,867 $ 2,701 For further discussion regarding our development program, please see Items 1 and 2.
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.
Payments of Principal and Interest on Senior Notes and Tranche A Loans At December 31, 2024, we have total principal payments due on our outstanding senior notes, including those of Viper, of $764 million in 2026, $1.3 billion in 2027, $73 million in 2028, $915 million in 2029 and $9.0 billion thereafter.
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.
Subject to regulatory restrictions and other factors discussed elsewhere in this report, we intend to continue opportunistically purchasing shares under this repurchase program primarily with funds from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure 60 Table of Contents programs.
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.
Investing Activities The majority of our net cash used for investing activities during the year ended December 31, 2024 and 2023 was for drilling and completion costs in conjunction with our development program as well as the purchase of oil and gas properties including the Endeavor Acquisition and Viper’s Tumbleweed Acquisitions in 2024 and the Lario Acquisition and Viper’s GRP Acquisition in 2023.
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.
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. ITEM 7A.
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.
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 and to finance the pending Double Eagle Acquisition.
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.
Return of Capital Commitment Beginning in the first quarter of 2024, our board of directors approved a return of capital commitment of at least 50% (down from 75%) of our quarterly free cash flow to our stockholders through repurchases under our share repurchase program, base dividends and variable dividends.
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.
As of December 31, 2024, 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. 63 Table of Contents 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.
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.
These cash inflows were partially offset by an increase in our cash operating expenses, excluding purchased oil expense, of 57 Table of Contents approximately $903 million related primarily to merger and integration costs incurred in connection with the Endeavor Acquisition and additional lease operating expenses, (ii) an increase of $253 million in cash paid for taxes, (iii) an increase of $123 million in cash paid for interest, net of capitalized amounts, and (iv) 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.
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.
No impairments were recorded for our proved oil and gas properties during the years ended December 31, 2024, 2023 and 2022. Based on the historical 12-month average trailing SEC prices for oil and natural gas throughout 2024 and into 2025, we are not currently projecting a full cost ceiling impairment in the first quarter of 2025.
Based on the historical 12-month average trailing SEC prices 57 Table of Contents 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.
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 agreements, Tranche A Loans and senior notes, (iii) payments of other contractual obligations, (iv) cash commitments for dividends and repurchases of securities, and the pending Double Eagle Acquisition. 2025 Capital Spending Plan We currently estimate that our 2025 capital budget, which gives effect to the pending Double Eagle Acquisition, will be $3.80 billion to $4.20 billion, including $3.13 billion to $3.44 billion for horizontal drilling and completions, $280 million to $320 million for non-operated activity and capital workovers and $390 million to $440 million spent on infrastructure, midstream and environmental capital expenditures.
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. 54 Table of Contents 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.
Financing Activities During the year ended December 31, 2024, net cash used in financing activities was primarily attributable to $5.5 billion of proceeds from the issuance of the April 2024 Notes, $900 million in borrowings on our Tranche A Loans, net of repayments, $476 million in proceeds from the Viper 2024 Equity Offering, $451 million in proceeds from the sale of our shares of Viper’s Class A common stock and $2 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.
These assumptions and judgments are reviewed and adjusted as facts and circumstances change. At December 31, 2024, 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.
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.
As of December 31, 2024, the maximum credit amount available under our credit agreement was $2.5 billion, which may be increased to a total maximum commitment amount of $2.6 billion, with no outstanding borrowings and $2.5 billion available for future borrowings. Our credit agreement matures on June 2, 2029.
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.
The pricing level depends on certain rating agencies’ ratings of our long-term senior unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.325% per year on the unused portion of the commitment for our revolving credit facilities.
We are obligated to pay a quarterly commitment fee ranging from 0.100% to 0.250% per year on the unused portion of the commitment for our revolving credit facility.
We do not require our customers to post collateral, and the failure or inability of our significant customers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. 64 Table of Contents Interest Rate Risk We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facilities, Tranche A Loans and changes in the fair value of our fixed rate debt.
We do not require our customers to post collateral and the failure or inability of our significant customers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results.
In 2024, 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, resulted in the full release of Viper’s remaining valuation allowance of $156 million.
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.
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. 58 Table of Contents As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and/or equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements.
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.
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.
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.
We cannot predict events that may lead to future price volatility and the near-term energy outlook remains subject to heightened levels of uncertainty. Further, the prices we receive for production depend on many other factors outside of our control.
We cannot predict events that may lead to future price volatility and the near-term energy outlook remains subject to heightened levels of uncertainty as discussed in Item 1 A . Risk Facto rs .
In September, we received an upgrade from two of the three major ratings agencies in the U.S., Standard and Poor’s Global Ratings Services and Fitch Investor Services. 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).
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.
The remainder of our free cash flow will be used primarily to reduce debt. On February 21, 2025, our board of directors declared a base cash dividend for the fourth quarter of 2024 of $1.00 per share of common stock. Free cash flow is a non-GAAP financial measure.
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.
At December 31, 2024, our unevaluated properties totaled $22.7 billion, which consisted of 433,335 net undeveloped leasehold acres with approximately 4,290 net acres set to expire in 2025.
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.
Since the inception of the stock repurchase program, we have repurchased an aggregate 25.84 million shares of our common stock for a total cost of $3.5 billion, excluding excise tax, as of February 21, 2025.
Since the inception of the stock repurchase program through February 20, 2026, we 55 Table of Contents 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.
On September 18, 2024, our board of directors approved an increase in our common stock repurchase program from $4.0 billion to $6.0 billion, excluding excise tax.
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.
Revolving Credit Facilities and Other Debt Instruments As of December 31, 2024, our debt, including the debt of Viper, consisted of approximately $12.0 billion in aggregate outstanding principal amount of senior notes, $900 million in aggregate outstanding short-term borrowings under the Tranche A Loans and $261 million in aggregate outstanding borrowings under revolving credit facilities.
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.
For our Tranche A Loans, we are obligated to pay a quarterly commitment fee equal to 0.125% per year on the aggregate principal amount of the commitments. We believe significant interest rate changes would not have a material near-term impact on our future earnings or cash flows.
We are also obligated to pay a commitment fee equal to 0.125% per year on the aggregate principal amount of the commitments for the 2025 Term Loan. During the year ended December 31, 2025, the weighted average interest rate on borrowings under the 2025 Term Loan was 5.64%.
For additional information on our variable interest rate debt at December 31, 2024, see Note 9— Debt in Item 8. Financial Statements and Supplementary Data of this report. Historically, we have at times used interest rates swaps to manage our exposure to (i) interest rate changes on our floating-rate date, and (ii) fair value changes on our fixed rate debt.
During the year ended December 31, 2025, the weighted average interest rate on borrowings under the Viper 2025 Term Loan was 5.72%. 60 Table of Contents Historically, we have at times used interest rate swaps to manage our exposure to (i) interest rate changes on our floating-rate debt, and (ii) fair value changes on our fixed rate debt.
The cash outflows were partially offset by (i) $394 million in net proceeds from the issuance of the Viper 2031 Notes and an additional $111 million in borrowings under credit facilities, net of repayments. Capital Resources Our working capital requirements are supported by our cash and cash equivalents and available borrowings under our revolving credit facility.
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.
See Note 10— Stockholders' Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program. Guarantor Financial Information Diamondback E&P is the sole guarantor under the indentures governing the outstanding Guaranteed Senior Notes.
Guarantor Financial Information Diamondback E&P is the sole guarantor under the indentures governing the outstanding Guaranteed Senior Notes.
December 31, 2024 Summarized Balance Sheets: (In millions) Assets: Current assets $ 933 Property and equipment, net $ 21,795 Other noncurrent assets $ 32 Liabilities: Current liabilities $ 2,943 Intercompany accounts payable, non-guarantor subsidiary $ 3,381 Long-term debt $ 10,978 Other noncurrent liabilities $ 2,979 Year Ended December 31, 2024 Summarized Statement of Operations: (In millions) Revenues $ 7,022 Income (loss) from operations $ 2,319 Net income (loss) $ 1,631 61 Table of Contents 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.
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 56 Table of Contents 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.
Viper LLC’s Credit Agreement The Viper LLC credit agreement, as amended to date, matures on September 22, 2028 and provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base and elected commitment amount of $1.3 billion.
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.
Removed
At December 31, 2024, there were $261 million of outstanding borrowings and $1.0 billion available for future borrowings under the Viper LLC credit agreement. For additional discussion of our outstanding debt as of December 31, 2024, see Note 9— Debt in Item 8. Financial Statements and Supplementary Data of this report.
Added
The majority of our net cash used in investing activities during the year ended December 31, 2024, was for the Endeavor Acquisition.
Removed
Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.
Added
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.
Removed
We currently expect to drill approximately 446 to 471 gross (406 to 428 net) horizontal wells and complete approximately 557 to 592 gross (526 to 560 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 11,500 feet. 59 Table of Contents The amount and timing of our capital expenditures are largely discretionary and within our control.
Added
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.
Removed
In addition to the senior notes, we have $900 million in aggregate outstanding borrowings under the Tranche A Loans due in 2025. See Note 9— Debt in Item 8. Financial Statements and Supplementary Data of this report for further discussion on the Tranche A Loans.
Added
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.
Removed
As used by us, free cash flow is defined as cash flow from operating activities before changes in working capital in excess of cash capital expenditures and other adjustments as determined by us.
Added
The amount and timing of our capital expenditures are largely discretionary and within our control.
Removed
We believe that free cash flow is useful to investors as it provides a measure to compare both cash flow from operating activities and additions to oil and natural gas properties across periods on a consistent basis.
Added
Financial Statements and Supplementary Data of this report for further details regarding our outstanding borrowing and interest expense.
Removed
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 16— Commitments and Contingencies in Item 8.
Added
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.
Removed
Pricing for oil and natural gas production can be volatile and unpredictable. We cannot predict events, including the outcome of the war in Ukraine and the Israel-Hamas war, along with other conflicts in the Middle East, changes in interest rates and inflation and global supply chain disruptions, that may lead to future price volatility.
Added
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.
Removed
Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by Diamondback E&P.
Added
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.
Added
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.
Added
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.
Added
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.

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