filings.toolsItem 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2024. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Part II. Item 1A. Risk Factors and Cautionary Statement Regarding Forward-Looking Statements**.
Overview
We are an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. As discussed in Note 1—Description of the Business and Basis of Presentation and Note 18—Segment Information of the notes to the condensed consolidated financial statements, as of September 30, 2025, we have one reportable segment, the upstream segment.
Third Quarter 2025 Financial and Operating Highlights
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Recorded net income of $1.0 billion.
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Paid dividends to stockholders of $289 million during the third quarter of 2025 and declared a base cash dividend payable in the fourth quarter of 2025 of $1.00 per share of common stock.
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Increased our common stock repurchase program authorization to $8.0 billion, excluding excise taxes, repurchased $603 million of our common stock, excluding excise taxes, and had approximately $3.1 billion available for future repurchases under our common stock repurchase program at September 30, 2025.
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Our cash operating costs were $10.05 per BOE, including lease operating expenses of $5.65 per BOE, cash general and administrative expenses of $0.55 per BOE and production and ad valorem taxes of $2.44 per BOE and gathering, processing and transportation expenses of $1.41 per BOE.
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Our average production was 942.9 MBOE/d.
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Drilled 107 gross horizontal wells in the Midland Basin and one gross horizontal well in the Delaware Basin and turned 137 gross operated horizontal wells (137 in the Midland Basin and none in the Delaware Basin) to production.
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Cash capital expenditures, excluding acquisitions, were $774 million.
Transactions and Recent Developments
Acquisitions and Divestitures
Diamondback Divestitures
EPIC Divestiture
On October 31, 2025, we divested our 27.5% equity interest in EPIC pursuant to a definitive purchase and sale agreement with Plains for approximately $504 million in cash and an additional $96 million in contingent consideration. On October 31, 2025, we used $500 million of the cash proceeds received from the EPIC Divestiture to partially repay principal borrowings under the Company’s 2025 Term Loan.
Divestiture of Water Assets to Deep Blue
On October 1, 2025, we divested EDS to Deep Blue, which was originally acquired in connection with the Endeavor Acquisition, in exchange for upfront net cash proceeds of $694 million and the potential for us to earn up to an additional $200 million in contingent consideration based on the achievement of certain completion thresholds for the years 2026 through 2028. As part of the divestiture, the Company renewed its 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. The cash proceeds from the divestiture were used to repay borrowings under the Credit Agreement and for general corporate purposes.
Viper Acquisitions and Divestitures
Pending Viper Divestiture of Non-Permian Assets
On October 30, 2025, Viper entered into an equity interest purchase agreement to divest all its non-Permian assets, including those acquired from Sitio, for a purchase price of approximately $670 million, subject to customary purchase price adjustments. The properties to be divested consist 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. The Pending Viper Non-Permian Divestiture is subject to customary closing conditions and is expected to close in the first quarter of 2026.
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, subject to further adjustments for transaction costs and certain customary post-closing adjustments, including the retirement of Sitio’s net debt of $1.2 billion. The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres.
Capital Transactions
Viper 2025 Notes Offering and Redemption of Notes
On July 23, 2025, Viper LLC issued the Viper 2025 Notes for an aggregate principal amount of $1.6 billion. Viper used a portion of the net proceeds from the issuance of the Viper 2025 Notes to redeem or satisfy and discharge, as applicable, approximately $780 million in aggregate principal amount of their previously outstanding senior notes, including accrued interest paid and redemption premiums. The Viper 2027 Notes were subsequently redeemed in full on November 1, 2025. Viper used the remaining net proceeds (i) to retire Sitio’s 7.875% senior notes due 2028, (ii) to repay borrowings under Sitio’s revolving credit facility, (iii) to pay fees, costs and expenses related to the redemption or repayment of such debt, and (iv) for general corporate purposes.
Viper Term Loan
In connection with the closing of the Sitio Acquisition, Viper LLC entered into the $500 million Viper Term Loan, which Viper drew in a single borrowing to partially fund the retirement of Sitio’s debt.
See Note 9—Debt of the notes to the condensed consolidated financial statements for further discussion of the capital transactions above.
Retirement of Notes
In the fourth quarter of 2025, we opportunistically repurchased principal amounts of $152 million of our 4.400% Senior Notes due 2051 and $51 million of our 4.250% Senior Notes due 2052 in open market transactions for total cash consideration of $167 million, including accrued interest paid, at an average of 82.3% of par value.
See Note 4—Acquisitions and Divestitures and Note 17—Subsequent Events of the notes to the condensed consolidated financial statements for further discussion of the transactions above.
Commodity Prices and Impairment
Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to tariffs or other trade barriers, and any resulting trade tensions, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. During the first nine months of 2025 and 2024, WTI prices averaged $66.65 and $77.61 per Bbl, respectively, and Henry Hub prices averaged $3.48 and $2.22 per MMBtu, respectively.
Given the overall decline in SEC Prices through the first three quarters of 2025 and into the fourth quarter of 2025 as compared to 2024, we believe a material non-cash impairment of our assets is reasonably likely to occur in the fourth quarter of 2025. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine an estimate of the amount or range of amounts of any potential impairment charge in the fourth quarter of 2025. Impairment charges affect our results of operations but do not reduce our cash flow.
For additional information around risks related to commodity prices, see Part II. Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.
Upstream Operations
Our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin within the Permian Basin. Additionally, our publicly-traded subsidiary, Viper, is focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin and derives royalty income and lease bonus income from such interests.
As of September 30, 2025, we had approximately 862,019 net acres in the Permian Basin, which primarily consisted of approximately 751,146 net acres in the Midland Basin and 110,873 net acres in the Delaware Basin.
The following table sets forth the total number of operated horizontal wells drilled and completed during the periods indicated:
| Three Months Ended September 30, 2025 | Nine Months Ended September 30, 2025 | ||||||||||||||||||||||||||||||||||||||||||||||
| Drilled | Completed**(1)** | Drilled | Completed**(2)** | ||||||||||||||||||||||||||||||||||||||||||||
| Area: | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||||
| Midland Basin | 107 | 97 | 137 | 127 | 352 | 326 | 361 | 342 | |||||||||||||||||||||||||||||||||||||||
| Delaware Basin | 1 | 1 | — | — | 4 | 4 | 15 | 13 | |||||||||||||||||||||||||||||||||||||||
| Total | 108 | 98 | 137 | 127 | 356 | 330 | 376 | 355 |
(1)The average lateral length for the wells completed during the third quarter of 2025 was 11,020 feet. Operated completions during the third quarter of 2025 consisted of 28 Lower Spraberry wells, 27 Wolfcamp A wells, 27 Wolfcamp B wells, 26 Jo Mill wells, 11 Middle Spraberry wells, 10 Dean wells, four Barnett wells, three Upper Spraberry wells and one Wolfcamp D.
(2)The average lateral length for the wells completed during the nine months ended September 30, 2025, was 12,060 feet. Operated completions during the nine months ended September 30, 2025, consisted of 80 Wolfcamp B wells, 77 Lower Spraberry wells, 71 Wolfcamp A wells, 54 Jo Mill wells, 32 Middle Spraberry wells, 22 Dean wells, 13 Upper Spraberry wells, 10 Barnett wells, eight Third Bone Spring wells, seven Wolfcamp D wells and two Second Bone Spring wells.
As of September 30, 2025, we operated the following wells:
| As of September 30, 2025 | |||||||||||||||||||||||||||||||||||
| Vertical Wells | Horizontal Wells | Total | |||||||||||||||||||||||||||||||||
| Area: | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||
| Midland Basin | 4,437 | 4,216 | 4,744 | 4,441 | 9,181 | 8,657 | |||||||||||||||||||||||||||||
| Delaware Basin | 105 | 93 | 516 | 477 | 621 | 570 | |||||||||||||||||||||||||||||
| Total | 4,542 | 4,309 | 5,260 | 4,918 | 9,802 | 9,227 |
As of September 30, 2025, we and Viper held interests in 54,868 gross (9,571 net) wells, including 1,988 gross (332 net) wells in which we have a non-operated working interest.
Consistent with our previously announced expected levels of activity for the remainder of 2025, we ran 13 rigs and five completion crews during the third quarter of 2025 to execute on our capital and operating plan, including holding oil production volumes relatively flat. While our development plan during the first two quarters of 2025 had reduced capital expenditure budgets compared to our original 2025 guidance, capital expenditures are expected to increase moderately in the fourth quarter of 2025 as part of our effort to hold oil production relatively flat. A core tenet of our plan to remain disciplined on our expenditures and moderating oil production is maximizing the consistency of our ability to operate efficiently at scale.
Guidance
Our revised development plan is presented below. Under the revised development plan, we target maintaining maximum operational flexibility in anticipation of the market revealing a stronger signal regarding the future of commodity prices. We currently plan to continue moderating oil production volumes through the end of 2025, while also improving per share metrics through increased efficiency and the use of our enhanced stock repurchase plan. As a result, we are raising our annual BOE guidance by approximately 2%, primarily to reflect the successful closing of the Sitio merger, coupled with continued improvements in gas capture efficiency. Additionally, we expect to reduce our debt in the fourth quarter of 2025 through the generation of cash flow from operations as well as from proceeds from the divestiture of non-core assets.
The following table presents our updated estimates of certain financial and operating results for the full year of 2025 and the fourth quarter of 2025:
| 2025 Guidance | |||||
| Net production - MBOE/d | 910 - 920 (from 890 - 910) | ||||
| Oil production - MBO/d | 495 - 498 (from 485 - 492) | ||||
| Q4 2025 oil production - MBO/d (total - MBOE/d) | 505 - 515 (927 - 963) | ||||
| (Unit costs $/BOE): | |||||
| Lease operating expenses, including workovers | $5.40 - $5.70 (from $5.30 - $5.70) | ||||
| General and administrative expenses - cash | $0.60 - $0.75 | ||||
| Non-cash stock-based compensation | $0.25 - $0.35 | ||||
| Depreciation, depletion, amortization and accretion | $14.50 - $15.50 | ||||
| Interest expense (net of interest income) | $0.60 - $0.80 | ||||
| Gathering, processing and transportation | $1.45 - $1.60 (from $1.60 - $1.75) | ||||
| Production and ad valorem taxes (% of revenue) | ~7% | ||||
| Q4 2025 cash taxes (in millions)(1)(2) | $270 - $350 |
(1)Includes approximately $175 million in tax impacts from asset divestitures in the fourth quarter.
(2)Includes estimated favorable impact on the year-to-date period of tax legislation enacted in the third quarter.
Results of Operations
Comparison of the Three Months Ended September 30, 2025, and June 30, 2025
As noted in “—Commodity Prices,” the markets for oil and natural gas are highly volatile and are influenced by a number of factors which can lead to significant changes in our results of operations and management’s operational strategy on a quarterly basis. Accordingly, our results of operations discussion focuses on a comparison of the current quarter’s results of operations with those of the immediately preceding quarter. We believe our discussion provides investors with a more meaningful analysis of material operational and financial changes which occurred during the quarter based on current market and operational trends.
The following table sets forth selected operating data for the periods indicated:
| Three Months Ended | |||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||
| Revenues (In millions): | |||||||||||
| Oil sales | $ | 2,994 | $ | 2,852 | |||||||
| Natural gas sales | 87 | 97 | |||||||||
| Natural gas liquid sales | 366 | 367 | |||||||||
| Total oil, natural gas and natural gas liquid revenues | $ | 3,447 | $ | 3,316 | |||||||
| Production Data: | |||||||||||
| Oil (MBbls) | 46,345 | 45,108 | |||||||||
| Natural gas (MMcf) | 115,353 | 110,119 | |||||||||
| Natural gas liquids (MBbls) | 21,180 | 20,248 | |||||||||
| Combined volumes (MBOE)(1) | 86,751 | 83,709 | |||||||||
| Daily oil volumes (BO/d) | 503,750 | 495,692 | |||||||||
| Daily combined volumes (BOE/d) | 942,946 | 919,879 | |||||||||
| Average Prices: | |||||||||||
| Oil ($ per Bbl) | $ | 64.60 | $ | 63.23 | |||||||
| Natural gas ($ per Mcf) | $ | 0.75 | $ | 0.88 | |||||||
| Natural gas liquids ($ per Bbl) | $ | 17.28 | $ | 18.13 | |||||||
| Combined ($ per BOE) | $ | 39.73 | $ | 39.61 | |||||||
| Oil, hedged ($ per Bbl)(2) | $ | 63.70 | $ | 62.34 | |||||||
| Natural gas, hedged ($ per Mcf)(2) | $ | 1.75 | $ | 1.45 | |||||||
| Natural gas liquids, hedged ($ per Bbl)(2) | $ | 17.28 | $ | 18.13 | |||||||
| Average price, hedged ($ per BOE)(2) | $ | 40.58 | $ | 39.89 |
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
(2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables provide information on the mix of our production for the periods indicated:
| Three Months Ended | |||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||
| Oil (MBbls) | 54 | % | 54 | % | |||||||
| Natural gas (MMcf) | 22 | 22 | |||||||||
| Natural gas liquids (MBbls) | 24 | 24 | |||||||||
| 100 | % | 100 | % |
| Three Months Ended September 30, 2025 | Three Months Ended June 30, 2025 | ||||||||||||||||||||||||||||||||||||||||||||||
| Midland Basin | Delaware Basin | Other | Total | Midland Basin | Delaware Basin | Other | Total | ||||||||||||||||||||||||||||||||||||||||
| Production Data: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) | 42,979 | 3,322 | 44 | 46,345 | 41,639 | 3,417 | 52 | 45,108 | |||||||||||||||||||||||||||||||||||||||
| Natural gas (MMcf) | 107,507 | 7,807 | 39 | 115,353 | 100,981 | 8,785 | 353 | 110,119 | |||||||||||||||||||||||||||||||||||||||
| Natural gas liquids (MBbls) | 19,927 | 1,227 | 26 | 21,180 | 18,846 | 1,390 | 12 | 20,248 | |||||||||||||||||||||||||||||||||||||||
| Total (MBOE) | 80,824 | 5,850 | 77 | 86,751 | 77,315 | 6,271 | 123 | 83,709 |
Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.
Our oil, natural gas and natural gas liquids revenues for the third quarter of 2025 increased by $131 million to $3.4 billion compared to the second quarter of 2025. The increase consisted of $100 million attributable to the 4% growth in our combined production volumes, and $31 million attributable to higher average prices received primarily for our oil production.
Approximately 53% of the increase in our combined production volumes is attributable to Viper’s Sitio Acquisition. The remainder of production growth is largely attributable to new wells added between periods.
Net Sales of Purchased Oil. We have entered into purchase transactions and separate sales transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments. The following table presents the net sales of purchased oil from third parties for the periods indicated:
| Three Months Ended | |||||||||||
| (In millions) | September 30, 2025 | June 30, 2025 | |||||||||
| Sales of purchased oil | $ | 459 | $ | 335 | |||||||
| Purchased oil expense | 455 | 331 | |||||||||
| Net sales of purchased oil | $ | 4 | $ | 4 |
Other Revenues. The following table presents other insignificant revenue for the periods indicated:
| Three Months Ended | |||||||||||
| (In millions) | September 30, 2025 | June 30, 2025 | |||||||||
| Other operating income | $ | 18 | $ | 27 |
Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated:
| Three Months Ended | |||||||||||||||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| Lease operating expenses | $ | 490 | $ | 5.65 | $ | 440 | $ | 5.26 |
Lease operating expenses increased for the third quarter of 2025 compared to the second quarter of 2025 primarily due to $14 million in additional electrical generation and artificial lift costs and $10 million in additional well workover costs. The remainder of the change is primarily due to the second quarter of 2025 including reductions in prior period water disposal cost estimates for properties acquired in the Endeavor Acquisition.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the periods indicated:
| Three Months Ended | |||||||||||||||||||||||||||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||||||||||||||||||||||||||
| (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 | $ | 163 | $ | 1.88 | 4.8 | % | $ | 156 | $ | 1.86 | 4.7 | % | |||||||||||||||||||||||
| Ad valorem taxes | 49 | 0.56 | 1.4 | 58 | 0.70 | 1.8 | |||||||||||||||||||||||||||||
| Total production and ad valorem expense | $ | 212 | $ | 2.44 | 6.2 | % | $ | 214 | $ | 2.56 | 6.5 | % |
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of oil, natural gas and natural gas liquids revenue remained consistent from the second quarter of 2025 to the third quarter of 2025.
Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes during the third quarter of 2025 compared to the second quarter of 2025 reflect a $14 million reduction to the accrual for 2024 based on actual assessments received in the third quarter of 2025 and other individually insignificant changes, which were partially offset by a $2 million increase related to properties acquired in Viper’s Sitio Acquisition.
Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expenses for the periods indicated:
| Three Months Ended | |||||||||||||||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| Gathering, processing and transportation | $ | 122 | $ | 1.41 | $ | 145 | $ | 1.73 |
The decrease in gathering, processing and transportation expenses primarily reflects a net reduction of $22 million due primarily to the second quarter of 2025 including $11 million of gathering and transportation charges related to the Double Eagle Acquisition, which were subsequently reclassified to revenue in the third quarter of 2025 as we integrated and conformed contracts to the Company’s financial statement presentation and other individually insignificant items.
Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the periods indicated:
| Three Months Ended | |||||||||||
| (In millions, except BOE amounts) | September 30, 2025 | June 30, 2025 | |||||||||
| Depletion of proved oil and natural gas properties | $ | 1,250 | $ | 1,230 | |||||||
| Depreciation and amortization of other property and equipment | 24 | 23 | |||||||||
| Other amortization | 3 | 4 | |||||||||
| Asset retirement obligation accretion | 9 | 9 | |||||||||
| Depreciation, depletion, amortization and accretion | $ | 1,286 | $ | 1,266 | |||||||
| Oil and natural gas properties depletion rate per BOE | $ | 14.41 | $ | 14.69 | |||||||
| Depreciation, depletion, amortization and accretion per BOE | $ | 14.82 | $ | 15.12 |
General and Administrative Expenses. The following table shows general and administrative expenses for the periods indicated:
| Three Months Ended | |||||||||||||||||||||||
| September 30, 2025 | June 30, 2025 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| General and administrative expenses | $ | 48 | $ | 0.55 | $ | 46 | $ | 0.55 | |||||||||||||||
| Non-cash stock-based compensation | 22 | 0.25 | 21 | 0.25 | |||||||||||||||||||
| Total general and administrative expenses | $ | 70 | $ | 0.80 | $ | 67 | $ | 0.80 |
Other Operating Costs and Expenses. The following table shows other operating costs and expenses for the periods indicated:
| Three Months Ended | |||||||||||
| (In millions) | September 30, 2025 | June 30, 2025 | |||||||||
| Merger and transaction expenses | $ | 17 | $ | 40 | |||||||
| Other operating expenses | $ | 36 | $ | 36 |
Merger and transaction expenses for the third quarter of 2025 primarily consisted of (i) approximately $15 million of employee severance payments made in connection with Viper’s Sitio Acquisition, and (ii) other individually insignificant items. Merger and transaction expenses for the second quarter of 2025 primarily consisted of (i) $29 million of advisory, legal and filing fees related to the 2025 Drop Down, and (ii) $13 million of employee severance and other costs incurred in connection with the Endeavor Acquisition.
Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on settlements of derivative instruments for the periods indicated:
| Three Months Ended | |||||||||||
| (In millions) | September 30, 2025 | June 30, 2025 | |||||||||
| Gain (loss) on derivative instruments, net(1) | $ | 120 | $ | (197) | |||||||
| Net cash received (paid) on settlements(1) | $ | 60 | $ | (37) |
(1)The three months ended September 30, 2025, and June 30, 2025, include cash paid on interest rate swaps terminated prior to their contractual maturity of $15 million, and $52 million, respectively.
The change from a loss to a gain on derivative instruments for the third quarter of 2025 compared to the second quarter of 2025 primarily reflects (i) a $330 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 $51 million increase in cash received on the settlement of natural gas contracts, (iii) a $37 million reduction in cash payments made to partially terminate $150 million of notional amount of our interest rate swaps during the third quarter of 2025 compared to partially terminating $450 million of notional amount of interest rate swaps during the second quarter of 2025, and (iv) other individually insignificant changes. These gains were partially offset by losses attributable to (i) a $64 million decrease in the value of our unsettled oil contracts due to an increase in market prices for oil compared to our contract prices, and (ii) a $53 million reduction in the value of our remaining interest rate swap contracts due to the early termination of additional notional value discussed above.
See Note 13—Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments.
Other Income (Expense). The following table shows other income and expenses for the periods indicated:
| Three Months Ended | |||||||||||
| (In millions) | September 30, 2025 | June 30, 2025 | |||||||||
| Interest expense, net | $ | (70) | $ | (56) | |||||||
| Other income (expense), net | $ | 108 | $ | (2) | |||||||
| Gain (loss) on extinguishment of debt | $ | (32) | $ | 55 | |||||||
| Income (loss) from equity investments, net | $ | 8 | $ | 4 |
The increase in interest expense, net for the third quarter of 2025 compared to the second quarter of 2025 primarily consists of (i) $16 million from the Viper 2025 Notes issued in July 2025, (ii) an $8 million decrease in capitalized interest costs, which increased interest expense, and (iii) $3 million of interest expense on the Viper Term Loan issued in connection with Viper’s Sitio Acquisition. These increases were partially offset by reductions of (i) $6 million attributable to Viper’s redemption of the Viper 2031 Notes, (ii) $5 million attributable to the repayment of the Tranche A Loans in May 2025, (iii) $5 million on the Company’s revolving credit facility due to lower average outstanding borrowings during the third quarter of 2025, and (iv) other individually insignificant changes.
See Note 9—Debt of the notes to the condensed consolidated financial statements for further details regarding outstanding borrowings.
The increase in other income (expense), net for the third quarter of 2025 compared to the second quarter of 2025 is primarily due to the third quarter of 2025 including (i) a $99 million gain on the sale of an equity method investment, (ii) a net gain of $23 million related to the receipt of additional proceeds in connection with the WTG Midstream Transaction, and (iii) other individually insignificant offsetting items.
See Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for further details regarding the Company’s divestiture activity.
The loss on extinguishment of debt in the third quarter of 2025 of $32 million was recorded on the redemption of the Viper 2031 Notes. The gain on extinguishment of debt in the second quarter of 2025 is due to the Company opportunistically repurchasing an aggregate principal amount of $252 million of its senior notes for total cash consideration, including accrued interest paid, of approximately $196 million.
See Note 9—Debt of the notes to the condensed consolidated financial statements for further details regarding the Company’s retirement of a portion of its senior notes during the third quarter of 2025.
Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the periods indicated:
| Three Months Ended | |||||||||||
| (In millions) | September 30, 2025 | June 30, 2025 | |||||||||
| Provision for (benefit from) income taxes | $ | 287 | $ | 204 |
The change in our income tax provision for the third quarter of 2025 compared to the second quarter of 2025 was primarily due to the increase in pre-tax income between the periods which resulted largely from gains on derivative contracts and gains on the divestiture of equity method investments recorded during the third quarter of 2025 as discussed above. See Note 12—Income Taxes of the notes to the condensed consolidated financial statements for further discussion of our income tax expense.
Comparison of the Nine Months Ended September 30, 2025, and 2024
The following table sets forth selected operating data for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| Revenues (In millions): | |||||||||||
| Oil sales | $ | 8,885 | $ | 6,025 | |||||||
| Natural gas sales | 396 | 38 | |||||||||
| Natural gas liquid sales | 1,139 | 566 | |||||||||
| Total oil, natural gas and natural gas liquid revenues | $ | 10,420 | $ | 6,629 | |||||||
| Production Data: | |||||||||||
| Oil (MBbls) | 134,288 | 79,540 | |||||||||
| Natural gas (MMcf) | 326,050 | 168,431 | |||||||||
| Natural gas liquids (MBbls) | 58,389 | 30,085 | |||||||||
| Combined volumes (MBOE)(1) | 247,019 | 137,697 | |||||||||
| Daily oil volumes (BO/d) | 491,897 | 290,292 | |||||||||
| Daily combined volumes (BOE/d) | 904,832 | 502,544 | |||||||||
| Average Prices: | |||||||||||
| Oil ($ per Bbl) | $ | 66.16 | $ | 75.75 | |||||||
| Natural gas ($ per Mcf) | $ | 1.21 | $ | 0.23 | |||||||
| Natural gas liquids ($ per Bbl) | $ | 19.51 | $ | 18.81 | |||||||
| Combined ($ per BOE) | $ | 42.18 | $ | 48.14 | |||||||
| Oil, hedged ($ per Bbl)(2) | $ | 65.27 | $ | 74.86 | |||||||
| Natural gas, hedged ($ per Mcf)(2) | $ | 2.14 | $ | 0.96 | |||||||
| Natural gas liquids, hedged ($ per Bbl)(2) | $ | 19.51 | $ | 18.81 | |||||||
| Average price, hedged ($ per BOE)(2) | $ | 42.92 | $ | 48.53 |
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
(2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables set forth the mix of our production data by product and basin for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| Oil (MBbls) | 54 | % | 58 | % | |||||||
| Natural gas (MMcf) | 22 | 20 | |||||||||
| Natural gas liquids (MBbls) | 24 | 22 | |||||||||
| 100 | % | 100 | % |
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | ||||||||||||||||||||||||||||||||||||||||||||||
| Midland Basin | Delaware Basin | Other | Total | Midland Basin | Delaware Basin | Other | Total | ||||||||||||||||||||||||||||||||||||||||
| Production Data: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) | 123,959 | 10,199 | 130 | 134,288 | 65,741 | 13,722 | 77 | 79,540 | |||||||||||||||||||||||||||||||||||||||
| Natural gas (MMcf) | 298,829 | 26,553 | 668 | 326,050 | 128,978 | 39,033 | 420 | 168,431 | |||||||||||||||||||||||||||||||||||||||
| Natural gas liquids (MBbls) | 54,542 | 3,772 | 75 | 58,389 | 24,008 | 6,043 | 34 | 30,085 | |||||||||||||||||||||||||||||||||||||||
| Total (MBOE) | 228,306 | 18,397 | 316 | 247,019 | 111,245 | 26,271 | 181 | 137,697 |
Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.
Our oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2025, increased by $3.8 billion, or 57%, to $10.4 billion from the same period in 2024 primarily due to a $4.7 billion increase driven by the 79% growth in our combined production volumes. This increase was partially offset by a net reduction of $924 million primarily due to lower average prices received for our oil production for the nine months ended September 30, 2025.
Approximately 56% of the increase in our combined production volumes is attributable to the Endeavor Acquisition and 8% is attributable to the Double Eagle Acquisition. The remainder of production growth is largely attributable to new wells added between periods.
Net Sales of Purchased Oil. We entered into purchase transactions and separate sale transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments. The following table presents the net sales of purchased oil from third parties for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Sales of purchased oil | $ | 1,168 | $ | 698 | |||||||
| Purchased oil expense | 1,168 | 696 | |||||||||
| Net sales of purchased oil | $ | — | $ | 2 |
Other Revenues. The following table shows the other revenues for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Other operating income | $ | 62 | $ | 28 |
Other operating income increased for the nine months ended September 30, 2025, compared to the same period in 2024 primarily due to (i) recording $30 million in midstream and service revenues attributable to assets acquired in the Endeavor Acquisition, and (ii) a $17 million increase in lease bonus income received during 2025. These increases were partially offset by a $13 million reduction in midstream revenues following the divestiture of certain midstream assets in connection with the TRP Exchange that closed in the fourth quarter of 2024.
Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated:
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| Lease operating expenses | $ | 1,338 | $ | 5.42 | $ | 825 | $ | 5.99 |
Lease operating expenses increased for the nine months ended September 30, 2025, compared to the same period in 2024 primarily due to (i) $368 million of costs associated with operating wells acquired in the Endeavor Acquisition, (ii) an additional $55 million of costs from higher legacy production volumes, (iii) $44 million in additional well workover costs, (iv) $34 million of costs attributable to operating wells acquired in the Double Eagle Acquisition, (v) a $25 million increase in maintenance costs, and (vi) individually insignificant offsetting changes. The decrease in the overall rate per BOE for the nine
months ended September 30, 2025, compared to the same period in 2024 was primarily the result of lower disposal costs associated with properties acquired in connection with the Endeavor Acquisition and the Double Eagle Acquisition.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the periods indicated:
| Nine Months Ended September 30, | |||||||||||||||||||||||||||||||||||
| 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 | $ | 490 | $ | 1.98 | 4.7 | % | $ | 294 | $ | 2.14 | 4.4 | % | |||||||||||||||||||||||
| Ad valorem taxes | 164 | 0.67 | 1.6 | 119 | 0.86 | 1.8 | |||||||||||||||||||||||||||||
| Total production and ad valorem expense | $ | 654 | $ | 2.65 | 6.3 | % | $ | 413 | $ | 3.00 | 6.2 | % |
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of revenue from sales of oil, natural gas and natural gas liquids increased in 2025 compared to 2024 due primarily to the 2024 period including a $17 million refund for the settlement of an audit, which reduced production taxes in the prior year period.
Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the nine months ended September 30, 2025, as compared to the same period in 2024 increased by $45 million, primarily due to additional taxes incurred on properties acquired since September 30, 2024. The rate of ad valorem taxes per BOE and as a percentage of revenue declined due to a reduction in expected ad valorem tax rates on legacy properties for 2025 compared to the rates during 2024.
Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expenses for the periods indicated:
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| Gathering, processing and transportation | $ | 378 | $ | 1.53 | $ | 261 | $ | 1.90 |
The increase in gathering, processing and transportation expenses for the nine months ended September 30, 2025, compared to the same period in 2024 is attributable primarily to (i) $36 million incurred on additional production acquired in the Endeavor Acquisition, (ii) $30 million associated with production from new wells completed between the nine months ended September 30, 2025, and September 30, 2024, (iii) $29 million associated with transportation costs incurred to meet our minimum volume commitments on certain pipelines, (iv) $19 million related to new firm transportation contracts that became effective during the nine months ended September 30, 2025, (v) $10 million related to properties acquired in the TRP Exchange, and (vi) other individually insignificant changes. The decrease in the overall rate per BOE for the nine months ended September 30, 2025, compared to the same period in 2024 was driven by recording gathering, processing and transportation charges for the majority of production from the Endeavor Acquisition, and to a lesser extent, the Double Eagle Acquisition, as a reduction to revenue in accordance with the terms of the acquired contracts.
Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| (In millions, except BOE amounts) | 2025 | 2024 | |||||||||
| Depletion of proved oil and natural gas properties | $ | 3,545 | $ | 1,638 | |||||||
| Depreciation and amortization of other property and equipment | 70 | 36 | |||||||||
| Other amortization | 7 | 6 | |||||||||
| Asset retirement obligation accretion | 27 | 14 | |||||||||
| Depreciation, depletion, amortization and accretion | $ | 3,649 | $ | 1,694 | |||||||
| Oil and natural gas properties depletion rate per BOE | $ | 14.35 | $ | 11.90 | |||||||
| Depreciation, depletion, amortization and accretion per BOE | $ | 14.77 | $ | 12.30 |
The increase in depletion of proved oil and natural gas properties of $1.9 billion for the nine months ended September 30, 2025, as compared to the same period in 2024 consists primarily of $1.3 billion from growth in production volumes and $605 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 TWR Acquisition subsequent to the third quarter of 2024.
Additionally, depreciation and amortization of other property and equipment increased in connection with the acquisition of other assets in the Endeavor Acquisition.
General and Administrative Expenses. The following table shows general and administrative expenses for the periods indicated:
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| General and administrative expenses | $ | 149 | $ | 0.60 | $ | 92 | $ | 0.67 | |||||||||||||||
| Non-cash stock-based compensation | 61 | 0.25 | 49 | 0.36 | |||||||||||||||||||
| Total general and administrative expenses | $ | 210 | $ | 0.85 | $ | 141 | $ | 1.03 |
General and administrative expenses increased for the nine months ended September 30, 2025, compared to the same period in 2024 primarily due to (i) a $45 million increase in employee compensation and benefit costs related to increasing headcount largely from the Endeavor Acquisition and annual discretionary compensation adjustments, (ii) an $11 million increase in software, contract labor and professional services costs, and (iii) other individually insignificant items.
Other Operating Costs and Expenses. The following table shows the other operating costs and expenses for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Merger and transaction expenses | $ | 94 | $ | 273 | |||||||
| Other operating expenses | $ | 111 | $ | 68 |
Merger and transaction expenses for the nine months ended September 30, 2025, were primarily comprised of (i) $38 million of employee severance and other costs incurred in connection with the Endeavor Acquisition, (ii) $21 million in advisory, legal and filing fees incurred by the Company and $10 million incurred by Viper related to the 2025 Drop Down, (iii) $15 million of employee severance payments made in connection with Viper’s Sitio Acquisition, (iv) $10 million in advisory and legal fees related to the TRP Exchange, and (v) other individually insignificant costs. Merger and transaction expenses for the nine months ended September 30, 2024, relate to costs incurred for the Endeavor Acquisition.
See Note 5—Endeavor Energy Resources, LP Acquisition and Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for further details regarding the Endeavor Acquisition as well as the Sitio Acquisition and TRP Exchange, respectively.
The increase in other operating expenses for the nine months ended September 30, 2025, compared to the same period in 2024 primarily resulted from a $70 million increase in midstream service costs related to additional production from the Endeavor Acquisition, which was partially offset by an $11 million net decrease in loss on the sale of property, plant and equipment, and a $12 million reduction in impairment charges taken on certain midstream assets in 2024 as well as other individually insignificant items.
Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on settlements of derivative instruments for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Gain (loss) on derivative instruments, net(1) | $ | 149 | $ | 101 | |||||||
| Net cash received (paid) on settlements(1) | $ | 108 | $ | (36) |
(1)The nine months ended September 30, 2025, and 2024 include cash paid on interest rate swaps terminated prior to their contractual maturity of $67 million and $37 million, respectively.
The increase in gain on derivative instruments for the nine months ended September 30, 2025, compared to the same period in 2024 primarily reflects (i) a $177 million increase in cash received on the settlement of natural gas contracts, (ii) a $40 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 which was in a liability position, and (iii) a $20 million decrease in cash paid for the semi-annual settlement of our interest rate derivatives. These gains were partially offset by losses attributable primarily to (i) a $126 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) a $49 million increase in cash paid for the settlement of our oil contracts primarily related to premiums on our oil puts, (iii) a $14 million decrease in the value of our unsettled oil contracts primarily due to an increase in market prices for oil compared to our contract prices, and (iv) other individually insignificant changes. See Note 13—Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments.
Other Income (Expense). The following table shows other income and expenses for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Interest expense, net | $ | (166) | $ | (101) | |||||||
| Other income (expense), net | $ | 133 | $ | 87 | |||||||
| Gain (loss) on extinguishment of debt | $ | 23 | $ | 2 | |||||||
| Income (loss) from equity investments, net | $ | 20 | $ | 23 |
Interest expense, net increased by $65 million for the nine months ended September 30, 2025, compared to the same period in 2024. This increase primarily consisted of (i) a $129 million reduction in interest income attributable to holding funds raised for the Endeavor Acquisition in cash in short-term interest bearing accounts during the nine months ended September 30, 2024, which reduced interest expense, (ii) $91 million of additional interest expense on the April 2024 Notes, (iii) $43 million of interest expense on the 2025 Term Loan issued in March 2025, (iv) $35 million of interest expense on the 2035 Notes issued in March 2025, (v) $16 million of interest expense on the Viper 2025 Notes issued in July 2025, (vi) $16 million of additional interest expense on the Company’s revolving credit facility due to higher average outstanding borrowings, and (vii) $14 million of additional interest expense on the Tranche A Loans that were repaid in May 2025. These increases were partially offset by (i) a $250 million increase in capitalized interest costs, which reduces interest expense, (ii) a $28 million reduction attributable to the amortization of debt issuance costs related to our terminated bridge facility being fully amortized in 2024, and (iii) other individually insignificant changes.
See Note 9—Debt of the notes to the condensed consolidated financial statements for further details regarding outstanding borrowings.
Other income (expense), net for the nine months ended September 30, 2025, increased compared to the same period in 2024, primarily due to an increase of $62 million in the gain recognized on the sale of various equity method investments in 2025 compared to 2024. This net gain was partially offset by a $15 million decrease in the value of an investment recorded at fair value during the nine months ended September 30, 2025, compared to the same period in 2024 and other individually insignificant items.
The increase in gain (loss) on extinguishment of debt is primarily attributable to the Company opportunistically repurchasing a portion of its senior notes during the second quarter of 2025 net of the loss recognized on the redemption of Viper’s 2031 Notes as discussed in “**—Results of Operations - Comparison of the Three Months Ended September 30, 2025, and June 30, 2025.”
See Note 9—Debt of the notes to the condensed consolidated financial statements for further details regarding the Company’s retirement of a portion of its senior notes during the second quarter of 2025.
Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the periods indicated:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Provision for (benefit from) income taxes | $ | 894 | $ | 685 |
The change in our income tax provision for the nine months ended September 30, 2025, compared to the same period in 2024 was primarily due to the increase in pre-tax income resulting largely from higher revenues attributable to properties acquired in connection with the Endeavor Acquisition. See Note 12—Income Taxes of the notes to the condensed consolidated financial statements for further discussion of our income tax expense.
Liquidity and Capital Resources
Overview of Sources and Uses of Cash
Historically, our primary sources of liquidity have included cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility, borrowings under term loans, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties, repayment of debt and returning capital to stockholders. At September 30, 2025, we had approximately $2.4 billion of liquidity consisting of $106 million in standalone cash and cash equivalents and $2.3 billion available under our credit facility. As discussed above, we have revised our capital budget guidance for 2025 to $3.45 billion to $3.55 billion to prioritize free cash flow generation. At September 30, 2025, we had approximately $14 million of senior notes, excluding the Viper 2027 Notes, maturing in the next 12 months.
Future cash flows are subject to a number of variables, including the level of oil and natural gas production and volatility of commodity prices. Further, significant additional capital expenditures will be required to more fully develop our properties. Prices for our commodities are determined primarily by prevailing market conditions, regional and worldwide economic activity, weather and other substantially variable factors. These factors are beyond our control and are difficult to predict as discussed further in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2024, and in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2025, filed with the SEC on May 7, 2025. 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 of the notes to the condensed consolidated financial statements and Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk. The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.
Cash Flow
Our cash flows for the nine months ended September 30, 2025, and 2024 are presented below:
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In millions) | |||||||||||
| Net cash provided by (used in) operating activities | $ | 6,415 | $ | 4,072 | |||||||
| Net cash provided by (used in) investing activities | (7,691) | (9,366) | |||||||||
| Net cash provided by (used in) financing activities | 1,664 | 5,082 | |||||||||
| Net increase (decrease) in cash | $ | 388 | $ | (212) |
Operating Activities
The increase in operating cash flows for the nine months ended September 30, 2025, compared to the same period in 2024 primarily resulted from (i) $3.8 billion in additional revenue, excluding sales of purchased oil, and (ii) an increase of $144 million in cash received on settlements of derivatives. These cash inflows were partially offset by (i) higher cash operating expenses, excluding purchased oil expense, of approximately $792 million, (ii) an increase of $1.0 billion in cash paid for taxes, and (iii) fluctuations in other working capital balances due primarily to the timing of when collections were made on accounts receivable and payments were made on accounts payable. See “—**Results of Operations” for discussion of significant changes in our revenues and expenses.
Investing Activities
The majority of our net cash used in investing activities during the nine months ended September 30, 2025, was for drilling and completion costs incurred in conjunction with our development program as well as the acquisition of properties and equipment for the Double Eagle Acquisition and Viper’s Sitio Acquisition. The majority of our net cash used in investing activities during the nine months ended September 30, 2024, was for the Endeavor Acquisition.
Capital Expenditure Activities
Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In millions) | |||||||||||
| Operated drilling and completion additions to oil and natural gas properties(1) | $ | (2,203) | $ | (1,785) | |||||||
| Capital workovers, non-operated additions to oil and natural gas properties and science | (205) | (13) | |||||||||
| Infrastructure, environmental and midstream additions | (172) | (136) | |||||||||
| Total | $ | (2,580) | $ | (1,934) |
(1) See “—Transactions and Recent Developments—Upstream Operations” above for additional detail on wells drilled and turned to production during the three and nine months ended September 30, 2025.
Financing Activities
During the nine months ended September 30, 2025, net cash provided by financing activities was primarily attributable to (i) $2.8 billion of proceeds from the issuance of the 2035 Notes and Viper 2025 Notes, (ii) $2.0 billion of proceeds from the 2025 Term Loan and the Viper Term Loan, (iii) $1.2 billion in proceeds from the Viper 2025 Equity Offering, (iv) $74 million in borrowings on our credit facilities, net of repayments. These cash inflows were partially offset by (i) $1.7 billion of repurchases as part of our and Viper’s share repurchase programs, (ii) $900 million in repayments on our Tranche A Loans, (iii) $870 million of dividends paid to stockholders, (iv) $672 million paid to retire senior notes, (v) $255 million in dividends paid to non-controlling interest, (vi) and various other individually insignificant costs.
During the nine months ended September 30, 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) $1.0 billion in borrowings under the Tranche A Loans, (iii) $476 million in proceeds from the Viper 2024 Equity Offering, and (iv) $451 million in proceeds from the public offering of Viper’s Class A common stock. These cash inflows were partially offset by (i) $1.3 billion of dividends paid to stockholders, (ii) $557 million of repurchases as part of the share repurchase programs, (iii) $157 million in dividends paid to non-controlling interest, (iv) $148 million in repayments under our credit facilities, net of borrowings, (v) $95 million of debt issuance costs primarily associated with the April 2024 Notes, Tranche A Loans and bridge facility, and (vi) $37 million in cash paid for tax withholdings on vested employee stock awards.
Capital Resources
Our working capital requirements are primarily supported by our cash and cash equivalents and available borrowings under our revolving credit facility. We may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term capital requirements.
As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Any prolonged volatility in the capital, financial and/or credit markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.
Revolving Credit Facilities and Other Debt Instruments
As of September 30, 2025, our debt, including the debt of Viper, consisted of approximately $14.1 billion in aggregate outstanding principal amount of senior notes, $1.5 billion in aggregate outstanding borrowings under the 2025 Term Loan Agreement, $500 million in aggregate outstanding borrowings under the Viper Term Loan and $335 million in aggregate outstanding borrowings under revolving credit facilities.
As of September 30, 2025, our Credit Agreement, which matures on June 12, 2030, had a maximum credit amount available of $2.5 billion, with $175 million outstanding borrowings and $2.3 billion available for future borrowings.
Viper LLC’s Revolving Credit Facility
The Viper LLC Revolving Credit Facility, which matures on June 12, 2030, provides for a commitment amount of $1.5 billion. As of September 30, 2025, the Viper LLC Revolving Credit Facility had $160 million in outstanding borrowings and $1.3 billion available for future borrowings.
For additional discussion of our debt as of September 30, 2025, see Note 9—Debt of the notes to the condensed consolidated financial statements.
Capital Requirements
In addition to future operating expenses and working capital commitments discussed in “—Transactions and Recent Developments—Upstream Operations,” our primary short and long-term liquidity requirements, excluding those of Viper, 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.
2025 Capital Spending Plan
Our board of directors has approved our revised 2025 capital budget guidance for drilling, midstream, infrastructure and environmental expenditures, which takes into consideration any impacts from Viper’s Sitio Acquisition. The capital budget was reduced during the first half of 2025 compared to original 2025 guidance as a result of our deliberate moderation of activity, coupled with material efficiency gains and synergy capture following the integration of recent acquisitions. Additionally, we have benefited from structural improvements in our cost base, including lower service pricing and an ever-optimizing supply chain given our size and scale. We expect an increase in activity for the remainder of 2025, and as a result, the low end of our capital budget guidance range for the full year 2025 has increased slightly from our prior guidance. Our current capital budget guidance ranges from approximately $3.45 billion to $3.55 billion, including $2.93 billion to $2.95 billion for operated horizontal drilling and completions, $300 million to $350 million for non-operated activity, capital workovers and science and $225 million to $250 million spent on infrastructure, midstream and environmental capital expenditures. We currently expect to drill approximately 445 to 465 gross (412 to 430 net) horizontal wells and complete approximately 510 to 520 gross (471 to 481 net) horizontal wells across our operated leasehold acreage in the Midland and Southern Delaware Basins, with an average lateral length of approximately 11,500 feet.
The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating 13 drilling rigs and five completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget in response to changes in commodity prices and overall market conditions.
Interest on 2035 Notes
On March 20, 2025, we issued $1.2 billion in aggregate principal amount of the 2035 Notes, as discussed further in Note 9—Debt. As a result, we expect to incur additional cash interest costs on the 2035 Notes of approximately $33 million in the fourth quarter of 2025, $133 million cumulatively in the years from 2026 through 2027, $133 million cumulatively in the years from 2028 through 2029 and $366 million cumulatively between 2030 and 2035.
Interest on Viper 2025 Notes
On July 23, 2025, Viper issued $1.6 billion in aggregate principal amount of the Viper 2025 Notes. In 2025, Viper does not expect to incur any cash interest costs on the Viper 2025 Notes. Viper expects to incur future cash interest costs on the Viper 2025 Notes of approximately $174 million cumulatively in the years from 2026 through 2027, $174 million cumulatively in the years from 2028 through 2029 and $402 million between 2030 and 2035.
Retirement of Notes
In the fourth quarter of 2025, we opportunistically repurchased principal amounts of $152 million of our 4.400% Senior Notes due 2051 and $51 million of our 4.250% Senior Notes due 2052 in open market transactions for total cash consideration of $167 million, including accrued interest paid, at an average of 82.3% of par value.
Return of Capital Commitment
Currently, our board of directors has approved a return of capital commitment of at least 50% of adjusted free cash flow to our stockholders through repurchases under our share repurchase program, base dividends and variable dividends. The remainder of our free cash flow will be used primarily to reduce debt. On October 30, 2025, our board of directors declared a base cash dividend for the third quarter of 2025 of $1.00 per share of common stock.
Adjusted free cash flow is a non-GAAP financial measure. As used by us, adjusted free cash flow is defined as cash flow from operating activities before changes in working capital in excess of cash capital expenditures and further adjusted for merger and transaction expenses, costs of early termination of derivatives and settlements of any treasury locks. We believe that adjusted 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.
On July 31, 2025, our board of directors approved a $2.0 billion increase in common stock repurchase authorization under our existing common stock repurchase program from $6.0 billion to $8.0 billion, excluding excise tax. Since the inception of the stock repurchase program, we have repurchased an aggregate of 36.1 million shares of our common stock for a total cost of $5.0 billion, excluding excise tax, as of October 31, 2025, leaving approximately $3.0 billion for future repurchases under such stock repurchase program, excluding excise tax. Subject to regulatory restrictions and other factors discussed elsewhere in this report, we intend to continue to purchase shares under this repurchase program opportunistically with available funds primarily from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs; however, the stock repurchase program is at the discretion of our board of directors and can be amended, terminated or suspended at any time. Repurchases may be executed in privately negotiated or open-market transactions, consistent with Rule 10b-18 under the Securities Exchange Act of 1934 and other applicable requirements. All shares repurchased will be retired. See Note 10—Stockholders’ Equity and Earnings (Loss) Per Share of the notes to the condensed consolidated financial statements for further discussion of our stock repurchase program.
Guarantor Financial Information
Diamondback E&P is the sole guarantor under the indentures governing the outstanding Guaranteed Senior Notes.
Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the indentures governing the Guaranteed Senior Notes, such as, with certain exceptions, (i) in the event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (ii) in the event Diamondback E&P ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (iii) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.
Diamondback E&P’s guarantees of the Guaranteed Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future
senior indebtedness, including its obligations under its revolving credit facility and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.
The rights of holders of the Guaranteed Senior Notes against Diamondback E&P may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback E&P’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback E&P, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary, and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.
| September 30, 2025 | December 31, 2024 | ||||||||||
| Summarized Balance Sheets: | (In millions) | ||||||||||
| Assets: | |||||||||||
| Current assets | $ | 988 | $ | 933 | |||||||
| Property and equipment, net | $ | 22,761 | $ | 21,795 | |||||||
| Other noncurrent assets | $ | 59 | $ | 32 | |||||||
| Liabilities: | |||||||||||
| Current liabilities | $ | 2,523 | $ | 2,943 | |||||||
| Intercompany accounts payable, non-guarantor subsidiary | $ | 6,285 | $ | 3,381 | |||||||
| Long-term debt | $ | 13,608 | $ | 10,978 | |||||||
| Other noncurrent liabilities | $ | 2,895 | $ | 2,979 |
| Nine Months Ended September 30, 2025 | |||||||||||
| Summarized Statement of Operations: | (In millions) | ||||||||||
| Revenues | $ | 5,204 | |||||||||
| Income (loss) from operations | $ | 1,276 | |||||||||
| Net income (loss) | $ | 782 |
Critical Accounting Estimates
There have been no changes in our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024.
Recent Accounting Pronouncements
See Note 2—Summary of Significant Accounting Policies of the notes to the condensed consolidated financial statements for recent accounting pronouncements not yet adopted, if any.
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