10-Q – 2025-11-05 – fang-20250930.htm

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Diamondback Energy, Inc. and Subsidiaries
Notes to the Condensed Consolidated Financial Statements - (Continued)
(Unaudited)

15.     SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS

Nine Months Ended September 30,
2025 2024
(In millions)
Supplemental disclosure of cash flow information:

Cash (paid) received for income taxes, net $ ( 1,216 ) $ ( 191 )
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses $ 1,043   $ 710  

Common shares issued for acquisitions $ ( 2,536 ) $ ( 20,110 )
Viper LLC’s units issued for acquisition $ ( 1,445 ) $ —  

16.     COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine legal proceedings, disputes and claims arising in the ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, employment claims, claims alleging violations of antitrust laws, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company’s current operations. While the ultimate outcome of the pending proceedings, disputes or claims and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records accrued liabilities for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Environmental Matters

The United States Department of the Interior, Bureau of Safety and Environmental Enforcement, ordered several oil and gas operators, including a corporate predecessor of Energen Corporation, to perform decommissioning and reclamation activities related to a Louisiana offshore oil and gas production platform and related facilities. In response to the insolvency of the operator of record, the government ordered the former operators and/or alleged former lease record title owners to decommission the platform and related facilities. The Company has agreed to an arrangement with other operators to contribute to a trust to fund the decommissioning costs, however, the Company’s portion of such costs are not expected to be material.

Several coastal Louisiana parishes and the State of Louisiana have filed numerous lawsuits under Louisiana’s State and Local Coastal Resources Management Act (“SLCRMA”) against numerous oil and gas producers seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone. The Company is a defendant in five of these cases. The Company has exercised contractual indemnification rights where applicable. Plaintiffs’ SLCRMA theories are unprecedented and there remains significant uncertainty about the claims (both as to scope and damages). Although the Company cannot predict the ultimate outcome of these matters, the Company believes the claims lack merit and intends to continue vigorously defending these lawsuits.

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Diamondback Energy, Inc. and Subsidiaries
Notes to the Condensed Consolidated Financial Statements - (Continued)
(Unaudited)

17.     SUBSEQUENT EVENTS

Third Quarter 2025 Dividend Declaration

On October 30, 2025, the board of directors of the Company declared a base cash dividend for the third quarter of 2025 of $ 1.00 per share of common stock, payable on November 20, 2025, to its stockholders of record at the close of business on November 13, 2025. Future base and variable dividends are at the discretion of the Company’s board of directors.

Diamondback Divestitures

EPIC Divestiture

On October 31, 2025, the Company divested its 27.5 % equity interest in EPIC Crude Holdings, LP (“EPIC”) pursuant to a definitive purchase and sale agreement with Plains All American Pipeline, L.P. and Plains GP Holdings (collectively, “Plains”) for approximately $ 504  million in cash and an additional $ 96  million in contingent consideration (the “EPIC Divestiture”). The contingent cash payment is due should the capacity expansion of EPIC be formally sanctioned before year-end 2027. On October 31, 2025, the Company 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, the Company divested Environmental Disposal Systems, LLC (“EDS”), its subsidiary, to Deep Blue, which was originally acquired in connection with the Endeavor Acquisition, in exchange for upfront net cash proceeds of $ 694  million. The transaction provides for the potential for the Company 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 Company’s equity ownership interest in Deep Blue remained at 30 % following the closing of the transaction. The cash proceeds from the divestiture were used to repay borrowings under the Credit Agreement and for general corporate purposes.

As of September 30, 2025, the assets related to this divestiture met the criteria to be classified as held for sale on the Company’s condensed consolidated balance sheets. See Note 6— Property and Equipment for additional discussion about the balance sheet classification of these assets as of September 30, 2025.

Viper Divestiture

Pending 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, to an affiliate of GRP Energy Capital LLC and Warwick Capital Partners LLP for a purchase price of approximately $ 670  million, subject to customary purchase price adjustments (the “Pending Viper Non-Permian Divestiture”). 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.

Retirement of Notes

In the fourth quarter of 2025, the Company opportunistically repurchased an aggregate principal amount of approximately $ 203 million of its senior notes, which consisted of $ 152  million of the 4.400 % Senior Notes due 2051 and $ 51 million of the 4.250 % Senior Notes due 2052, in open market transactions for total cash consideration, including accrued interest paid, of approximately $ 167  million, at an average of 82.3 % of par value. These repurchases resulted in a gain on extinguishment of debt of approximately $ 33  million during the fourth quarter of 2025.

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Diamondback Energy, Inc. and Subsidiaries
Notes to the Condensed Consolidated Financial Statements - (Continued)
(Unaudited)

18.     SEGMENT INFORMATION

The Company is managed on a consolidated basis as one operating segment and one reportable segment, the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. This singular operating and reportable segment is comprised of (i) the Company and its wholly owned subsidiaries, and (ii) Viper and its consolidated subsidiaries, which have been aggregated due to the similarity in their economic characteristics, products and services, processes, type of customers, method of distribution for their products and the regulatory environment in which they operate. The upstream segment derives its revenue from customers through the sale of oil and natural gas products as well as other immaterial service contracts. See Note 3— Revenue from Contracts with Customers for further discussion of the Company’s sources of revenue.

The Chief Operating Decision Maker (“CODM”) uses the Company’s condensed consolidated financial results to make key operating decisions, assess performance and to allocate resources. The measures of segment profit or loss and total assets utilized by the CODM are net income and total assets as reported on the condensed consolidated statements of operations and the condensed consolidated balance sheets, respectively. The significant expense categories, their amounts and other segment items that are regularly provided to the CODM are those that are reported in the Company’s condensed consolidated statements of operations.

The CODM uses consolidated net income as a measure of profitability to evaluate segment performance and to make capital allocation decisions such as reinvestment in the business or return of capital through the payment of base and variable dividends or repurchases under the share repurchase program.
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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

• Recorded net income of $1.0 billion.

• 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.

• 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.

• 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.

• Our average production was 942.9 MBOE/d.

• 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.

• 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.
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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.

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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.

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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.

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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  %

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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.

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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 

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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 

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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.

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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  %

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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
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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.

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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.

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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.
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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)

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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.
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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.

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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
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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.

ITEM 3.    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. Pricing for oil and natural gas production can be volatile and unpredictable. We cannot predict events, including conflicts in the Middle East, changes in interest rates and inflation and global supply chain disruptions that may lead to future price volatility. 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.
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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 September 30, 2025, we had a net asset derivative position of $90 million related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of September 30, 2025, a 10% increase in forward curves associated with the underlying commodity would have decreased the net asset position by $27 million to $63 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset position by $71 million to $161 million. 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 September 30, 2025, see Note 13— Derivatives of the notes to the condensed consolidated financial statements.

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 $1.3 billion at September 30, 2025), and to a lesser extent, receivables resulting from joint interest and other receivables (approximately $244 million at September 30, 2025).

Joint interest receivables arise from billings to entities that own partial interests in wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. 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.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facilities, 2025 Term Loan and changes in the fair value of our fixed rate debt.

Outstanding borrowings under our Credit Agreement bear interest at a per annum rate elected by Diamondback E&P that is equal to (i) term SOFR or (ii) an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. At September 30, 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. 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.

Outstanding borrowings under the 2025 Term Loan bear interest at a per annum rate elected by the Company that is equal to (i) Adjusted Term SOFR or (ii) an alternate base rate (which is equal to the greatest of (a) the Federal Funds effective rate plus 0.50%, (b) the prime rate, (c) Adjusted Term SOFR plus 1.0%, and (d) 1.0%), in each case plus the applicable margin. At September 30, 2025, 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 the 2025 Term Loan. We are 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.

Borrowings under the Viper LLC Revolving Credit Facility bear interest at a per annum rate elected by Viper LLC that is equal to term SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. For Viper LLC’s revolving credit facility, 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 term SOFR, in each case based on the pricing level. Viper is obligated to pay a commitment fee equal to 0.125% to 0.325% per year on the aggregate principal amount of the commitments.

Borrowings under the Viper Term Loan bear interest at a per annum rate elected by Viper LLC that is equal to term SOFR or an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 1-month term SOFR plus 1.0%, subject to a 1.0% floor), in each case plus the applicable margin. For the Viper Term Loan, the applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate loans and from 1.250% to 2.125% per annum in the case of term SOFR loans, in each case based on the pricing level. The pricing level depends on the rating of Viper’s long-term senior unsecured debt by certain ratings agencies. Viper is obligated to pay a commitment fee equal to 0.20% per annum on the aggregate principal amount of the commitments.
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The pricing levels described above depend on certain rating agencies’ ratings of our long-term senior unsecured debt and on the ratings of Viper’s long-term senior unsecured debt as applicable. We believe significant interest rate changes would not have a material near-term impact on our future earnings or cash flows. For additional information on our variable interest rate debt at September 30, 2025, see Note 9— Debt of the notes to the condensed consolidated financial statements.

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. At September 30, 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. 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 September 30, 2025, our receive-fixed, pay-variable interest rate swaps were in a liability position of $31 million and the weighted average variable rate was 5.81%. For additional information on our interest rate swaps, see Note 13— Derivatives of the notes to the condensed consolidated financial statements.

ITEM 4.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures . Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of September 30, 2025, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of September 30, 2025, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting . Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the Sitio Acquisition on August 19, 2025. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating Sitio’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there have not been any changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2025, that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Diamondback has elected to use a $1 million threshold for disclosing certain environmental proceedings to which a federal, state or local governmental authority is a party .

We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, employment claims, claims alleging violations of antitrust laws, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, results of operations or cash flows. See Note 16— Commitments and Contingencies of the notes to the condensed consolidated financial statements.

ITEM 1A.    RISK FACTORS

Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.

As of the date of this filing, we continue to be subject to the risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 26, 2025, Part II, Item 1A Risk Factors in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2025, filed with the SEC on May 7, 2025, and in subsequent filings we make with the SEC. There have been no material changes in our risk factors from those described 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.

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended September 30, 2025, 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)
July 1, 2025 - July 31, 2025 1,618 $ 142.32  1,618 $ 3,472 
August 1, 2025 - August 31, 2025 1,332 $ 140.19  1,332 $ 3,285 
September 1, 2025 - September 30, 2025 1,339 $ 139.24  1,336 $ 3,099 
Total 4,289 $ 140.70  4,286

(1) Includes 3,426 shares of common stock repurchased from executives in order to satisfy tax withholding requirements. Such shares are canceled and retired immediately upon repurchase.
(2) The average price paid per share includes any commissions paid to repurchase stock.
(3) On July 31, 2025, our board of directors approved a $2.0 billion increase in our common stock repurchase authorization 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.
(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. All dollar amounts presented exclude such excise taxes, as applicable.

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ITEM 5.    OTHER INFORMATION

On August 13, 2025 , Charles A. Meloy , a member of the board of directors of the Company, adopted a Rule 10b5-1 trading agreement intended to satisfy Rule 10b5-1(c), as amended. The plan relates to the sale of up to 110,000 shares of our common stock between November 12, 2025, and May 8, 2026 . The shares covered by this plan include shares of common stock currently held by Wolfrock Energy, L.L.C., a Texas limited liability company of which Mr. Meloy is the sole manager and has voting and dispositive power over the shares of common stock.

None of the Company’s other directors or officers adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended September 30, 2025.

On October 31, 2025, the Company’s board of directors approved certain amendments to our Fifth Amended and Restated Bylaws, effective immediately (as amended and restated, the “Sixth Amended and Restated Bylaws”). Among other things, the Sixth Amended and Restated Bylaws:
(i) clarify and enhance procedural mechanics and disclosure requirements relating to stockholders calling special meetings and stockholder director nominations and submissions of proposals, including requiring additional background information from proposed director nominees;
(ii) adopt a federal forum provision, selecting federal courts as the exclusive forum for claims under the Securities Act, unless the Company consents in writing to the selection of an alternative forum; and
(iii) make other technical, conforming, modernizing and clarifying amendments.
The foregoing summary does not purport to be complete and is qualified in its entirety by reference to the full text of the Sixth Amended and Restated Bylaws, a copy of which is filed as Exhibit 3.3 hereto.

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ITEM 6.    EXHIBITS

EXHIBIT INDEX
Exhibit Number Description

3.1 Second Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on June 14, 2023).

3.2 Certificate of Amendment No. 1 to Second Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 10, 2024).

3.3*
Sixth Amended and Restated Bylaws of the Company, adopted as of October 31,2025 .

4.1 Indenture, dated as of July 23, 2025, between Viper Energy Partners LLC and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K (file No. 001-36505) filed by Former Viper on July 23, 2025).

4.2 Second Supplemental Indenture, dated as of August 19, 2025, by and among Viper Opco, New Viper and Computershare Trust Company, National Association (incorporated by reference to Exhibit 4.8 of the Current Report on Form 8-K (File No. 001-42807) filed by New Viper on August 19, 2025).

10.1 Term Loan Credit Agreement, dated as of July 23, 2025, by and among Viper Energy Partners LLC, Former Viper, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent (incorporated by reference to Exhibit 4.3 of the Current Report on Form 8-K (File No. 001-36505) filed by Former Viper on July 23, 2025).

22.1 List of Issuers and Subsidiary Guarantors (incorporated by reference to Exhibit 22.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 5, 2021).

31.1* Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

31.2* Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

32.1** Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

32.2** Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

101 The following financial information from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Changes in Stockholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements.

104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

______________

*
Filed herewith.

**
The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DIAMONDBACK ENERGY, INC.

Date: November 5, 2025 /s/ Kaes Van’t Hof
Kaes Van’t Hof
Chief Executive Officer
(Principal Executive Officer)

Date: November 5, 2025 /s/ Jere W. Thompson III
Jere W. Thompson III
Chief Financial Officer
(Principal Financial Officer)

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