10-Q – 2025-08-06 – fang-20250630.htm

On June 2, 2025, Viper and Viper LLC entered into the Sitio Merger Agreement with Sitio and Sitio OpCo in an all-equity transaction valued at approximately $4.1 billion, including the redemption of Sitio’s net debt of approximately $1.1 billion as of June 30, 2025. The mineral and royalty interests to be acquired in the pending 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. Upon completion of the pending Sitio Acquisition, Viper expects to own 85,700 net royalty acres in the Permian Basin, approximately 43% of which will be operated by us and an average 1.8% net royalty interest in approximately 33,300 gross producing horizontal wells (approximately 608 net wells) with estimated average production of 64 - 68 MBO/d (122 - 130 MBOE/d) in the fourth quarter of 2025. The pending Sitio Acquisition is expected to close in the third quarter of 2025, subject to approval by a majority of the stockholders of Sitio and the satisfaction or waiver of other closing conditions. On June 2, 2025, Diamondback, Diamondback E&P and EER LLP, who together hold a majority of the voting power of Viper’s common stock, delivered a written consent approving the Sitio Merger Agreement, which constitutes the requisite approval of Viper’s stockholders under the Sitio Merger Agreement.

See Note 4— Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for further discussion of the transactions above.

Repurchase of Notes

In the second quarter of 2025, we opportunistically repurchased an aggregate principal amount of approximately $252 million of our outstanding senior notes, which consisted of $27 million of our 3.125% Senior Notes due 2031, $111 million of our 4.400% Senior Notes due 2051, $94 million of our 4.250% Senior Notes due 2052 and $20 million of our 5.750% Senior Notes due 2054, all in open market transactions for total cash consideration of $196 million, including accrued interest paid, at an average of 76.8% of par value. Further, Viper also opportunistically repurchased principal amounts of $50 million of its Viper 2027 Notes in open market transactions for total cash consideration of $50 million, at an average of 99.7% of par value. We may in the future opportunistically repurchase outstanding debt securities, in open market or privately negotiated transactions.

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 Viper 2025 Notes to redeem or satisfy and discharge, as applicable, $780 million in aggregate principal amount of their previously outstanding senior notes, including accrued interest paid and redemption premiums. Viper intends to use the remaining net proceeds (i) if the pending Sitio Acquisition is consummated, to redeem Sitio’s 7.875% senior notes due 2028, repay borrowings under Sitio’s revolving credit facility and pay any fees, costs and expenses related to the redemption or repayment of such debt, and (ii) for general corporate purposes. Viper LLC is not obligated to redeem or repurchase the Viper 2025 Notes if the pending Sitio Acquisition is not consummated.

Viper 2025 Term Loan

On July 23, 2025, Viper LLC entered into the Viper 2025 Term Loan for a two-year senior unsecured delayed draw term loan facility in an aggregate principal amount of $500 million. Viper intends to draw on the term loan to partially redeem or repay, as applicable, Sitio’s debt at the closing of the pending Sitio Acquisition.

Viper LLC’s Revolving Credit Facility

On June 12, 2025, Viper and Viper LLC entered into the Viper LLC Revolving Credit Facility which replaced the previous revolving credit facility. As of June 30, 2025, the Viper LLC Revolving Credit Facility is guaranteed by certain subsidiaries of Viper LLC, and upon completion of the pending Sitio Acquisition, such subsidiary guarantee will be released and New Viper will become a guarantor under the Viper LLC Revolving Credit Facility. The Viper LLC Revolving Credit
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Facility provides for a senior unsecured revolving credit facility with a commitment amount of $1.5 billion and will mature on June 12, 2030, unless extended in accordance with the terms thereof.

2025 Term Loan Agreement

In connection with the Double Eagle Acquisition, we entered into the 2025 Term Loan Agreement. The 2025 Term Loan Agreement provided the Company with the ability to borrow up to $1.5 billion, which we drew in a single borrowing to fund a portion of the cash consideration for the Double Eagle Acquisition.

See Note 9— Debt and Note 17— Subsequent Events of the notes to the condensed consolidated financial statements for further discussion of the transactions above.

Commodity Prices

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to 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 six months ended June 30, 2025 and 2024, WTI prices averaged $70.81 and $78.81 per Bbl, respectively, and Henry Hub prices averaged $3.69 and $2.21 per MMBtu, respectively.

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 June 30, 2025, we had approximately 859,203 net acres, which primarily consisted of approximately 742,522 net acres in the Midland Basin and 116,681 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 June 30, 2025
Six Months Ended June 30, 2025

Drilled Completed (1)
Drilled Completed (2)

Area: Gross Net
Gross Net
Gross Net Gross Net
Midland Basin 121  113  108  103  245  229  224  215 
Delaware Basin 1  1  8  6  3  3  15  13 

Total 122  114  116  109  248  232  239  228 

(1) The average lateral length for the wells completed during the second quarter of 2025 was 13,402 feet. Operated completions during the second quarter of 2025 consisted of 31 Wolfcamp B wells, 21 Lower Spraberry wells, 14 Wolfcamp A wells, 13 Middle Spraberry wells, 11 Jo Mill wells, eight Dean wells, eight Upper Spraberry wells, five Third Bone Spring wells, three Wolfcamp D wells and two Barnett wells.
(2) The average lateral length for the wells completed during the six months ended June 30, 2025 was 12,656 feet. Operated completions during the six months ended June 30, 2025 consisted of 53 Wolfcamp B wells, 49 Lower Spraberry wells, 44 Wolfcamp A wells, 28 Jo Mill wells, 21 Middle Spraberry wells, 12 Dean wells, 10 Upper Spraberry wells, eight Third Bone Spring wells, six Wolfcamp D wells, six Barnett wells and two Second Bone Spring wells.

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As of June 30, 2025, we operated the following wells:

As of June 30, 2025
Vertical Wells Horizontal Wells Total
Area: Gross Net Gross Net Gross Net
Midland Basin 4,598  4,359  4,599  4,302  9,197  8,661 
Delaware Basin 170  150  515  476  685  626 

Total 4,768  4,509  5,114  4,778  9,882  9,287 

As of June 30, 2025, we and Viper held interests in 33,922 gross (9,687 net) wells, including 2,499 gross (378 net) wells in which we have a non-operated working interest.

In the second quarter of 2025, we released four rigs, reducing our activity from 17 rigs to 13 rigs. We currently expect to run 13 to 14 rigs and five completion crews for the remainder of 2025 to execute on our capital and operating plan discussed below. We continue to test ways to maximize efficiency and reduce costs in all facets of our organization, fighting the headwinds of lower commodity prices and increased steel prices due to tariffs directly increasing our casing costs. We expect casing costs to increase almost 25% through the course of 2025, raising the breakeven cost of nearly every well drilled in the United States in 2025.

Guidance

Our revised development plan, which does not give effect to the pending Sitio Acquisition, is presented below. Under our revised development plan, given the volatility in commodity markets and macroeconomic uncertainty, we intend to hold oil production flat for the remainder of 2025, reduce capital expenditures while maintaining one of the highest drilled but uncompleted inventories in the Permian Basin and use free cash flow to pay down debt and repurchase stock under our enhanced stock repurchase program. We believe this plan will allow us to maintain flexibility at current commodity prices and when commodity prices improve.

The following table presents our updated estimates of certain financial and operating results for the full year of 2025 and the third quarter of 2025:

2025 Guidance

Net production - MBOE/d 890 - 910 (from 857 - 900)
Oil production - MBO/d 485 - 492 (from 480 - 495)
Q3 2025 oil production - MBO/d (total - MBOE/d)
485 - 495 (890 - 920)

(Unit costs $/BOE):

Lease operating expenses, including workovers $5.30 - $5.70 (from $5.65 - $6.05)
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 (from $14.00 - $15.00)
Interest expense (net of interest income) $0.60 - $0.80 (from $0.40 - $0.65)
Gathering, processing and transportation
$1.60 - $1.75 (from $1.40 - $1.60)

Production and ad valorem taxes (% of revenue)
~7%
Corporate tax rate (% of pre-tax income) 23%
Cash tax rate (% of pre-tax income) 15% - 18% (from 19% - 22%)

Q3 2025 cash taxes (in millions) (1)(2)
$50 - $110

(1) Includes approximately $20-25 million from gains on sales of assets expected to close in the third 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 June 30, 2025 and March 31, 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 three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
June 30, 2025 March 31, 2025
Revenues (In millions):
Oil sales $ 2,852  $ 3,039 
Natural gas sales 97  212 
Natural gas liquid sales 367  406 
Total oil, natural gas and natural gas liquid revenues $ 3,316  $ 3,657 

Production Data:
Oil (MBbls) 45,108  42,835 
Natural gas (MMcf) 110,119  100,578 
Natural gas liquids (MBbls) 20,248  16,961 
Combined volumes (MBOE) (1)
83,709  76,559 

Daily oil volumes (BO/d) 495,692  475,944 
Daily combined volumes (BOE/d) 919,879  850,656 

Average Prices:
Oil ($ per Bbl) $ 63.23  $ 70.95 
Natural gas ($ per Mcf) $ 0.88  $ 2.11 
Natural gas liquids ($ per Bbl) $ 18.13  $ 23.94 
Combined ($ per BOE) $ 39.61  $ 47.77 

Oil, hedged ($ per Bbl) (2)
$ 62.34  $ 70.06 
Natural gas, hedged ($ per Mcf) (2)
$ 1.45  $ 3.34 
Natural gas liquids, hedged ($ per Bbl) (2)
$ 18.13  $ 23.94 
Average price, hedged ($ per BOE) (2)
$ 39.89  $ 48.89 

(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 three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
June 30, 2025 March 31, 2025
Oil (MBbls) 54  % 56  %
Natural gas (MMcf) 22  22 
Natural gas liquids (MBbls) 24  22 
100  % 100  %

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Three Months Ended June 30, 2025 Three Months Ended March 31, 2025
Midland Basin Delaware Basin Other
Total Midland Basin Delaware Basin Other
Total
Production Data:
Oil (MBbls) 41,639  3,417  52  45,108  39,341  3,460  34  42,835 
Natural gas (MMcf) 100,981  8,785  353  110,119  90,341  9,961  276  100,578 
Natural gas liquids (MBbls) 18,846  1,390  12  20,248  15,769  1,155  37  16,961 
Total (MBOE) 77,315  6,271  123  83,709  70,167  6,275  117  76,559 

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 second quarter of 2025 decreased by $0.3 billion to $3.3 billion compared to the first quarter of 2025. The net decrease was due to a $601 million reduction related to lower average prices received for our oil, natural gas and natural gas liquids production, which was partially offset by a $260 million increase attributable to the 9% growth in our combined production volumes.

Approximately 65% of the increase in our combined production volumes 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 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 three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
(In millions) June 30, 2025 March 31, 2025
Sales of purchased oil $ 335  $ 374 
Purchased oil expense 331  382 
Net sales of purchased oil
$ 4  $ (8)

Other Revenues. The following table presents other insignificant revenue for the three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
(In millions) June 30, 2025 March 31, 2025
Other operating income $ 27  $ 17 

Lease Operating Expenses. The following table shows lease operating expenses for the three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
June 30, 2025 March 31, 2025
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
Lease operating expenses $ 440  $ 5.26  $ 408  $ 5.33 

Lease operating expenses increased for the second quarter of 2025 compared to the first quarter of 2025 primarily due to (i) a $14 million increase due to higher production volumes primarily driven by the Double Eagle Acquisition and to a lesser extent, legacy wells, (ii) $13 million in additional well workover costs, and (iii) a $10 million increase related to changes in cost estimates for water disposal associated with the Endeavor Acquisition, and (iv) other individually insignificant offsetting changes.

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Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
June 30, 2025 March 31, 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 $ 156  $ 1.86  4.7  % $ 171  $ 2.23  4.7  %
Ad valorem taxes 58  0.70  1.8  57  0.75  1.5 
Total production and ad valorem expense $ 214  $ 2.56  6.5  % $ 228  $ 2.98  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 oil, natural gas and natural gas liquids revenue remained consistent from the first quarter of 2025 to the second quarter of 2025.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes remained relatively consistent during the second quarter of 2025 compared to the first quarter of 2025.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expense for the three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
June 30, 2025 March 31, 2025
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
Gathering, processing and transportation $ 145  $ 1.73  $ 111  $ 1.45 

The increase in gathering, processing and transportation expenses is primarily attributable to (i) a $15 million increase associated with transportation costs incurred to meet our minimum volume commitments on certain pipelines, (ii) an $11 million increase related to production volumes from properties acquired in connection with the Double Eagle Acquisition, (iii) a $7 million increase due to a new firm transportation contract that became effective in the second quarter of 2025, and (iv) 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 three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
(In millions, except BOE amounts) June 30, 2025 March 31, 2025
Depletion of proved oil and natural gas properties $ 1,230  $ 1,065 
Depreciation and amortization of other property and equipment 23  23 
Other amortization 4  — 
Asset retirement obligation accretion 9  9 
Depreciation, depletion, amortization and accretion $ 1,266  $ 1,097 
Oil and natural gas properties depletion rate per BOE $ 14.69  $ 13.91 
Depreciation, depletion, amortization and accretion per BOE $ 15.12  $ 14.33 

Depletion of proved oil and natural gas properties increased by $165 million in the second quarter of 2025 compared to the first quarter of 2025. This change was comprised of a $100 million increase due to growth in production volumes and a $65 million increase due to the higher depletion rate in the second quarter of 2025 following the Double Eagle Acquisition.

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General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
June 30, 2025 March 31, 2025
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
General and administrative expenses $ 46  $ 0.55  $ 55  $ 0.72 
Non-cash stock-based compensation 21  0.25  18  0.24 
Total general and administrative expenses $ 67  $ 0.80  $ 73  $ 0.96 

General and administrative expenses decreased in the second quarter of 2025 compared to the first quarter of 2025 primarily due to a reduction in anticipated discretionary employee compensation.

Other Operating Costs and Expenses. The following table shows other operating costs and expenses for the three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
(In millions) June 30, 2025 March 31, 2025
Merger and transaction expenses $ 40  $ 37 

Other operating expenses $ 36  $ 39 

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. Merger and transaction expenses for the first quarter of 2025 primarily consisted of (i) $23 million of employee severance costs and $2 million of information technology and other integration service costs incurred in connection with the Endeavor Acquisition, (ii) $10 million in advisory and legal fees related to the TRP Exchange, and (iii) other individually insignificant costs.

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 three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
(In millions) June 30, 2025 March 31, 2025
Gain (loss) on derivative instruments, net (1)
$ (197) $ 226 
Net cash received (paid) on settlements (1)
$ (37) $ 85 

(1) The three months ended June 30, 2025 includes cash paid on interest rate swaps terminated prior to their contractual maturity of $52 million.

The change from a gain to a loss on derivative instruments for the second quarter of 2025 compared to the first quarter of 2025 primarily reflects (i) a $407 million decrease in the value of our unsettled natural gas contracts due to an increase in market prices for natural gas compared to our contract prices, (ii) a $62 million decrease in cash received on the settlement of natural gas contracts, (iii) $59 million in additional cash payments made on our interest rate swaps, primarily due to the $52 million early termination of an aggregate $450 million of notional interest rate swaps during the second quarter of 2025, and (iv) other individually insignificant changes. These losses were partially offset by gains attributable to (i) a $56 million increase in the value of our remaining interest rate swap contracts driven by a decline in expected future interest rates, and (ii) a $55 million increase in the value of our unsettled oil contracts due to a decline in market prices for oil compared to our contract prices.

See Note 13— Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments.

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Other Income (Expense). The following table shows other income and expenses for the three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
(In millions) June 30, 2025 March 31, 2025
Interest expense, net $ (56) $ (40)
Other income (expense), net $ (2) $ 27 
Gain (loss) on extinguishment of debt $ 55  $ — 
Income (loss) from equity investments, net $ 4  $ 8 

The increase in interest expense, net for the second quarter of 2025 compared to the first quarter of 2025 primarily consists of (i) $22 million in additional interest expense from the 2025 Term Loan Agreement that was drawn on the closing date of the Double Eagle Acquisition, (ii) $15 million in additional interest expense from the 2035 Notes issued in March 2025, and (iii) a $10 million increase in interest expense on our and Viper LLC’s revolving credit facilities due to higher average outstanding borrowings during the second quarter of 2025. These increases were partially offset by a (i) a $24 million increase in capitalized interest costs, which decreased interest expense, (ii) an $8 million decrease due to the termination of our Tranche A Loans in May of 2025, 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.

The decrease in other income (expense), net for the second quarter of 2025 compared to the first quarter of 2025 is primarily due to the first quarter of 2025 including a gain of $42 million related to the receipt of additional proceeds in connection with the WTG Midstream Transaction, which was partially offset by an $11 million increase in the loss on the remeasurement of an investment recorded at fair value, and other individually insignificant 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 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 second quarter of 2025.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended June 30, 2025 and March 31, 2025:

Three Months Ended
(In millions) June 30, 2025 March 31, 2025
Provision for (benefit from) income taxes $ 204  $ 403 

The change in our income tax provision for the second quarter of 2025 compared to the first quarter of 2025 was primarily due to the decrease in pre-tax income between the periods which resulted largely from changes in revenues, operating expenses and the gain (loss) on derivative contracts 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 Six Months Ended June 30, 2025 and 2024

The following table sets forth selected operating data for the six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
2025 2024
Revenues (In millions):
Oil sales $ 5,891  $ 3,865 
Natural gas sales 309  55 
Natural gas liquid sales 773  355 
Total oil, natural gas and natural gas liquid revenues $ 6,973  $ 4,275 

Production Data:
Oil (MBbls) 87,943  50,003 
Natural gas (MMcf) 210,697  101,912 
Natural gas liquids (MBbls) 37,209  18,167 
Combined volumes (MBOE) (1)
160,268  85,155 

Daily oil volumes (BO/d) 485,873  274,742 
Daily combined volumes (BOE/d) 885,459  467,885 

Average Prices:
Oil ($ per Bbl) $ 66.99  $ 77.30 
Natural gas ($ per Mcf) $ 1.47  $ 0.54 
Natural gas liquids ($ per Bbl) $ 20.77  $ 19.54 
Combined ($ per BOE) $ 43.51  $ 50.20 

Oil, hedged ($ per Bbl) (2)
$ 66.10  $ 76.36 
Natural gas, hedged ($ per Mcf) (2)
$ 2.35  $ 1.20 
Natural gas liquids, hedged ($ per Bbl) (2)
$ 20.77  $ 19.54 
Average price, hedged ($ per BOE) (2)
$ 44.19  $ 50.44 

(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 six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
2025 2024
Oil (MBbls) 55  % 59  %
Natural gas (MMcf) 22  20 
Natural gas liquids (MBbls) 23  21 
100  % 100  %

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Six Months Ended June 30, 2025 Six Months Ended June 30, 2024
Midland Basin Delaware Basin Other
Total Midland Basin Delaware Basin Other
Total
Production Data:
Oil (MBbls) 80,980  6,877  86  87,943  40,922  9,016  65  50,003 
Natural gas (MMcf) 191,322  18,746  629  210,697  75,893  25,712  307  101,912 
Natural gas liquids (MBbls) 34,615  2,545  49  37,209  14,209  3,930  28  18,167 
Total (MBOE) 147,482  12,546  240  160,268  67,780  17,231  144  85,155 

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 six months ended June 30, 2025 increased by $2.7 billion, or 63%, to $7.0 billion from the same period in 2024 primarily due to a $3.4 billion increase driven by the 88% growth in our combined production volumes. This increase was partially offset by a net reduction of $665 million due to lower average prices received for our oil production for the six months ended June 30, 2025.

Approximately 63% of the increase in our combined production volumes is attributable to the Endeavor Acquisition and 6% 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 six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
(In millions) 2025 2024
Sales of purchased oil $ 709  $ 416 
Purchased oil expense 713  416 
Net sales of purchased oil $ (4) $ — 

Other Revenues. The following table shows the other revenues for the six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
(In millions) 2025 2024
Other operating income $ 44  $ 19 

Other operating income increased for the six months ended June 30, 2025 compared to the same period in 2024 primarily due to (i) recording $25 million in midstream and service revenues attributable to assets acquired in the Endeavor Acquisition, and (ii) a $10 million increase in lease bonus income received during 2025. These increases were partially offset by a $10 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 six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
2025 2024
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
Lease operating expenses $ 848  $ 5.29  $ 509  $ 5.98 

Lease operating expenses increased for the six months ended June 30, 2025 compared to the same period in 2024 primarily due to (i) $253 million of costs associated with operating wells acquired in the Endeavor Acquisition, (ii) a $44 million increase from higher legacy production volumes, (iii) a $35 million increase in well workover costs, (iv) $10 million of costs associated with operating wells acquired in the Double Eagle Acquisition, and (v) other individually insignificant changes.

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Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the six months ended June 30, 2025 and 2024:

Six Months Ended June 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 $ 327  $ 2.04  4.7  % $ 185  $ 2.17  4.3  %
Ad valorem taxes 115  0.72  1.6  75  0.88  1.8 
Total production and ad valorem expense $ 442  $ 2.76  6.3  % $ 260  $ 3.05  6.1  %

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 six months ended June 30, 2025 as compared to the same period in 2024 increased by $40 million, primarily due to additional taxes incurred on properties acquired since June 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 expense for the six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
2025 2024
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
Gathering, processing and transportation $ 256  $ 1.60  $ 159  $ 1.87 

The increase in gathering, processing and transportation expenses for the six months ended June 30, 2025 compared to the same period in 2024 is attributable primarily to (i) $25 million associated with production from new wells completed between the six months ended June 30, 2025 and June 30, 2024, (ii) $22 million from additional production from wells acquired in the Endeavor Acquisition, (iii) $15 million associated with transportation costs incurred to meet our minimum volume commitments on certain pipelines, (iv) $12 million related to new firm transportation contracts that became effective during the six months ended June 30, 2025, (v) $11 million from properties acquired as part of the Double Eagle Acquisition, (vi) $7 million from the annual escalation of contractual gathering and transportation rates, and (vii) $5 million related to properties acquired in the TRP Exchange.

Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
(In millions, except BOE amounts) 2025 2024
Depletion of proved oil and natural gas properties $ 2,295  $ 917 
Depreciation and amortization of other property and equipment 46  23 
Other amortization 4  4 
Asset retirement obligation accretion 18  8 
Depreciation, depletion, amortization and accretion $ 2,363  $ 952 
Oil and natural gas properties depletion rate per BOE $ 14.32  $ 10.77 
Depreciation, depletion, amortization and accretion per BOE $ 14.74  $ 11.18 

The increase in depletion of proved oil and natural gas properties of $1.4 billion for the six months ended June 30, 2025 as compared to the same period in 2024 consists primarily of $809 million from growth in production volumes and $569 million due to an increase in the depletion rate resulting largely from the addition of higher value leasehold costs and proved
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reserves from the Endeavor Acquisition, the Double Eagle Acquisition and, to a lesser extent, Viper’s Tumbleweed Acquisitions subsequent to the second 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 six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
2025 2024
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
General and administrative expenses $ 101  $ 0.63  $ 59  $ 0.69 
Non-cash stock-based compensation 39  0.24  33  0.39 
Total general and administrative expenses $ 140  $ 0.87  $ 92  $ 1.08 

General and administrative expenses increased for the six months ended June 30, 2025 compared to the same period in 2024 primarily due to (i) a $30 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 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 six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
(In millions) 2025 2024
Merger and transaction expenses $ 77  $ 15 
Other operating expenses $ 75  $ 33 

Merger and transaction expenses for the six months ended June 30, 2025 were primarily comprised of (i) $34 million of employee severance and other costs incurred in connection with the Endeavor Acquisition, (ii) $30 million in advisory, legal and filing fees related to the 2025 Drop Down, (iii) $10 million in advisory and legal fees related to the TRP Exchange, and (iv) other individually insignificant costs. Merger and transaction expenses for the six months ended June 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 and TRP Exchange, respectively.

The increase in other operating expenses for the six months ended June 30, 2025 compared to the same period in 2024 primarily resulted from a $49 million increase in midstream service costs related to additional production from the Endeavor Acquisition, which was partially offset by a $10 million decrease in impairment losses due to the write off of certain saltwater disposal wells recorded during the six months ended June 30, 2024, and 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 six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
(In millions) 2025 2024
Gain (loss) on derivative instruments, net (1)
$ 29  $ (30)
Net cash received (paid) on settlements (1)
$ 48  $ (32)

(1) The six months ended June 30, 2025 includes cash paid on interest rate swaps terminated prior to their contractual maturity of $52 million.

The change from a loss to a gain on derivative instruments for the six months ended June 30, 2025 compared to the same period in 2024 primarily reflects gains attributable to (i) a $121 million increase in cash received on the settlement of natural gas contracts, (ii) a $95 million increase in the value of our unsettled interest rate swap contracts primarily due to a
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decline in expected future interest rates, (iii) a $57 million increase in the value of our unsettled oil contracts primarily due to a decrease in market prices for oil compared to our contract prices, and (iv) a $20 million decrease in cash paid for the settlement of our interest rate derivatives. These gains were partially offset by losses attributable primarily to (i) a $172 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 $32 million increase in cash paid for the settlement of our oil contracts, (iii) a $28 million increase in losses on the early termination of interest rate derivatives, 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 six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
(In millions) 2025 2024
Interest expense, net $ (96) $ (83)
Other income (expense), net $ 25  $ (2)

Gain (loss) on extinguishment of debt $ 55  $ 2 
Income (loss) from equity investments, net $ 12  $ 17 

Interest expense, net increased by $13 million for the six months ended June 30, 2025 compared to the same period in 2024. This increase primarily consisted of (i) $92 million of additional interest expense on the April 2024 Notes, (ii) $62 million due to a reduction in interest income received during the six months ended June 30, 2025, (iii) $22 million in interest incurred on the 2025 Term Loan Agreement, (iv) $19 million in interest incurred on the 2035 Notes issued in March of 2025, (v) $18 million in interest incurred on the Tranche A Loans, (vi) $11 million in interest on our revolving credit facility, and (vii) other individually insignificant changes. These increases were largely offset by (i) an additional $182 million in capitalized interest costs, which reduce interest expense, and (ii) a $25 million reduction in the amortization of debt issuance costs related primarily to our terminated bridge facility being fully amortized in 2024.

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 six months ended June 30, 2025 increased compared to the same period in 2024, primarily due to a gain of $42 million from additional proceeds received related to the WTG Midstream Transaction as discussed further in Note 4— Acquisitions and Divestitures of the notes to the condensed consolidated financial statements. This gain was partially offset by a $12 million decrease in the value of an investment recorded at fair value during the six months ended June 30, 2025 compared to the same period in 2024 and other individually insignificant items.

The increase in gain (loss) on extinguishment of debt is primarily attributable to the Company opportunistically repurchasing a portion its senior notes during the second quarter of 2025 as discussed in “ —Results of Operations - Comparison of the Three Months Ended June 30, 2025 and March 31, 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 six months ended June 30, 2025 and 2024:

Six Months Ended June 30,
(In millions) 2025 2024
Provision for (benefit from) income taxes $ 607  $ 475 

The change in our income tax provision for the six months ended June 30, 2025 compared to the same period in 2024 was primarily due to the increase in pre-tax income resulting largely from higher revenues, along with changes in gain (loss) on derivative instruments, net 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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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, 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 June 30, 2025, we had approximately $2.1 billion of liquidity consisting of $191 million in standalone cash and cash equivalents and $1.9 billion available under our credit facility. As discussed above, we have revised our capital budget guidance for 2025 to $3.40 billion to $3.60 billion to prioritize free cash flow generation. At June 30, 2025, we had approximately $14 million of senior 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 six months ended June 30, 2025 and 2024 are presented below:

Six Months Ended June 30,
2025 2024
(In millions)
Net cash provided by (used in) operating activities $ 4,032  $ 2,863 
Net cash provided by (used in) investing activities (5,632) (1,200)
Net cash provided by (used in) financing activities 1,657  4,663 
Net increase (decrease) in cash $ 57  $ 6,326 

Operating Activities

The increase in operating cash flows for the six months ended June 30, 2025 compared to the same period in 2024 primarily resulted from (i) $2.7 billion in additional revenue, excluding sales of purchased oil, and (ii) an increase of $80 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 $764 million, (ii) an increase of $664 million in cash paid for taxes, (iii) an increase of $34 million in cash paid for interest, and (iv) fluctuations in other working capital balances due primarily to the timing of when collections were made on accounts receivable and payments were made on accounts payable. 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 six months ended June 30, 2025 and 2024 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.

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Capital Expenditure Activities

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

Six Months Ended June 30,
2025 2024
(In millions)
Operated drilling and completion additions to oil and natural gas properties (1)
$ (1,571) $ (1,154)
Capital workovers, non-operated additions to oil and natural gas properties and science (111) (11)
Infrastructure, environmental and midstream additions (124) (81)
Total $ (1,806) $ (1,246)

(1) See “— Transactions and Recent Developments—Upstream Operations ” above for additional detail on wells drilled and turned to production during the three and six months ended June 30, 2025.

Financing Activities

During the six months ended June 30, 2025, net cash provided by financing activities was primarily attributable to (i) $1.5 billion of proceeds from the 2025 Term Loan Agreement, (ii) $1.2 billion of proceeds from the issuance of the 2035 Notes, (iii) $1.2 billion in proceeds from the Viper 2025 Equity Offering and (iv) $659 million in borrowings on our credit facilities, net of repayments. These cash inflows were partially offset by (i) $983 million of repurchases as part of our and Viper’s share repurchase programs, (ii) $900 million in repayments on our Tranche A Loans, (iii) $581 million of dividends paid to stockholders, (iv) $244 million in repurchases of senior notes, (v) $177 million in dividends paid to non-controlling interest, (vi) and various other individually insignificant costs.

During the six months ended June 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, and (ii) $451 million in proceeds from the public offering of Viper’s Class A common stock. These cash inflows were partially offset by (i) $900 million of dividends paid to stockholders, (ii) $98 million in dividends to non-controlling interest, (iii) $93 million of debt issuance costs primarily associated with the April 2024 Notes, Tranche A Loans and bridge facility, (iv) $86 million in repayments under credit facilities, net of borrowings, (v) $42 million of repurchases as part of the share repurchase programs, and (vi) $37 million in cash paid for tax withholdings on vested employee stock awards.

Capital Resources

Our working capital requirements are primarily supported by our cash and cash equivalents and available borrowings under our revolving credit facility. We may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term capital requirements.

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Any prolonged volatility in the capital, financial and/or credit markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Revolving Credit Facilities and Other Debt Instruments

As of June 30, 2025, our debt, including the debt of Viper, consisted of approximately $12.9 billion in aggregate outstanding principal amount of senior notes, $1.5 billion in aggregate outstanding borrowings under the 2025 Term Loan Agreement and $920 million in aggregate outstanding borrowings under revolving credit facilities.

As of June 30, 2025, the maximum credit amount available under our credit agreement was $2.5 billion, with $595 million outstanding borrowings and $1.9 billion available for future borrowings. Our credit agreement matures on June 12, 2030.

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Viper LLC ’ s Revolving Credit Facility and Other Viper Debt Instruments

The Viper LLC Revolving Credit Facility, which matures on June 12, 2030, provides for a commitment amount of $1.5 billion. As of June 30, 2025, the Viper LLC Revolving Credit Facility had $325 million in outstanding borrowings and $1.2 billion available for future borrowings.

On July 23, 2025, Viper LLC entered into the Viper 2025 Term Loan for a two-year senior unsecured delayed draw term loan facility in an aggregate principal amount of $500 million. Viper intends to draw on the term loan to partially redeem or repay, as applicable, Sitio’s debt at the closing of the pending Sitio Acquisition.

On July 23, 2025, Viper issued $1.6 billion in aggregate principal amount of the Viper 2025 Notes for net proceeds of approximately $1.58 billion, after underwriters’ discounts and transaction costs. Viper used a portion of the net proceeds to redeem or satisfy and discharge, as applicable, $780 million in aggregate principal amount of their previously outstanding senior notes. Viper intends to use the remaining net proceeds (i) if the pending Sitio Acquisition is consummated, to redeem Sitio’s 7.875% senior notes due 2028, repay borrowings under Sitio’s revolving credit facility and pay any fees, costs and expenses related to the redemption or repayment of such debt, and (ii) for general corporate purposes. Viper LLC is not obligated to redeem or repurchase the Viper 2025 Notes if the pending Sitio Acquisition is not consummated.

For additional discussion of our debt as of June 30, 2025, see Note 9— Debt and Note 17— Subsequent Events 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 agreements, 2025 Term Loan Agreement 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 the recent weakness in commodity prices and our reduced activity levels to prioritize free cash flow generation. The revised capital budget excludes any impact of Viper’s pending Sitio Acquisition, which is expected to close in the third quarter of 2025. Our capital budget guidance for the full year 2025 is reduced from our prior guidance to approximately $3.40 billion to $3.60 billion, including $2.85 billion to $2.95 billion for operated horizontal drilling and completions, $250 million to $300 million for non-operated activity, capital workovers and science and $300 million to $350 million spent on infrastructure, midstream and environmental capital expenditures. We currently expect to drill approximately 425 to 450 gross (395 to 418 net) horizontal wells and complete approximately 490 to 515 gross (458 to 482 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 11,500 feet.

The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating 13 drilling rigs and five completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget in response to changes in commodity prices and overall market conditions.

Interest on 2035 Notes

On March 20, 2025, we issued $1.2 billion in aggregate principal amount of the 2035 Notes, as discussed further in Note 9— Debt . As a result, we expect to incur additional future cash interest costs on the 2035 Notes of approximately $33 million in 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.

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Viper Redemption of Notes

On July 23, 2025, Viper redeemed all of their Viper 2031 Notes and satisfied and discharged all of their Viper 2027 Notes using proceeds from the Viper 2025 Notes Offering. Viper intends to use the remaining proceeds from the Viper 2025 Notes Offering and borrowings under the Viper 2025 Term Loan (i) if the pending Sitio Acquisition is consummated, to redeem Sitio’s 7.875% senior notes due 2028, repay borrowings under Sitio’s revolving credit facility and pay any fees, costs and expenses related to the redemption or repayment of such debt, and (ii) for general corporate purposes. The pending Sitio Acquisition is expected to close in the third quarter of 2025, subject to the satisfaction or waiver of closing conditions.

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 future 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.

Return of Capital Commitment

Currently, our board of directors has approved a return of capital commitment of at least 50% of 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 July 31, 2025, our board of directors declared a base cash dividend for the second quarter of 2025 of $1.00 per share of common stock.

Free cash flow is a non-GAAP financial measure. As used by us, free cash flow is defined as cash flow from operating activities before changes in working capital in excess of cash capital expenditures and other adjustments as determined by us. We believe that free cash flow is useful to investors as it provides a measure to compare both cash flow from operating activities and additions to oil and natural gas properties across periods on a consistent basis.

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 32.9 million shares of our common stock for a total cost of $4.5 billion, excluding excise tax, as of August 1, 2025, leaving approximately $3.5 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. See Note 10— Stockholders’ Equity and Earnings (Loss) Per Share of the notes to the condensed consolidated financial statements.

Guarantor Financial Information

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

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

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

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

June 30, 2025 December 31, 2024
Summarized Balance Sheets: (In millions)
Assets:
Current assets $ 768  $ 933 
Property and equipment, net $ 22,538  $ 21,795 
Other noncurrent assets $ 44  $ 32 
Liabilities:
Current liabilities $ 2,365  $ 2,943 
Intercompany accounts payable, non-guarantor subsidiary $ 5,399  $ 3,381 
Long-term debt $ 14,021  $ 10,978 
Other noncurrent liabilities $ 2,634  $ 2,979 

Six Months Ended June 30, 2025
Summarized Statement of Operations: (In millions)
Revenues $ 3,352 
Income (loss) from operations $ 824 
Net income (loss) $ 480 

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 the outcome of the war in Ukraine and the Israel-Hamas war along with other conflicts in the Middle East, changes in interest rates and inflation and global supply chain disruptions that may lead to future price volatility. We cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty. Further, the prices we receive for production depend on many other factors outside of our control.

We 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 June 30, 2025, we had a net asset derivative position of $49 million related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of June 30, 2025, a 10% increase in forward curves associated with the underlying commodity would have increased the net asset position by $10 million to $59 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net asset
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position by $9 million to $40 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 June 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 June 30, 2025), and to a lesser extent, receivables resulting from joint interest and other receivables (approximately $218 million at June 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 Agreement 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 June 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 Agreement 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 June 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 Agreement. 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 Agreement.

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.

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 June 30, 2025, see Note 9— Debt of the notes to the condensed consolidated financial statements.

Historically, we have at times used interest rates swaps to manage our exposure to (i) interest rate changes on our floating-rate date, and (ii) fair value changes on our fixed rate debt. At June 30, 2025, we have interest rate swap agreements for an aggregate $450 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 June 30, 2025, our receive-fixed, pay-variable interest rate swaps were in a liability position of $46 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.

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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 June 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 June 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 Endeavor Acquisition on September 10, 2024. 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 Endeavor’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 were no changes in our internal control over financial reporting that occurred during the quarter ended June 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, in addition to the factors discussed elsewhere in this report, 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 June 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)
April 1, 2025 - April 30, 2025 1,892 $ 129.50  1,892 $ 1,855 
May 1, 2025 - May 31, 2025 515 $ 135.25  514 $ 1,786 
June 1, 2025 - June 30, 2025 586 $ 143.13  586 $ 1,702 
Total 2,993 $ 133.16  2,992

(1) Includes 1,302 shares of common stock repurchased from executives in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.
(2) The average price paid per share includes any commissions paid to repurchase stock.
(3) On 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. As of August 1, 2025, approximately $3.5 billion remains available for future repurchases under such stock repurchase program, 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.
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(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.

ITEM 5.    OTHER INFORMATION

None of the Company’s 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 June 30, 2025.

ITEM 6.    EXHIBITS

EXHIBIT INDEX
Exhibit Number Description
2.1# Agreement and Plan of Merger, dated as of February 11, 2024, by and among the Company, Endeavor, Merger Sub I, Merger Sub II and the Company Representative (for purposes of certain sections set forth therein) (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on February 12, 2024).

2.2# Letter Agreement, amending the Merger Agreement, by and among the Company, Endeavor, Merger Sub I, Merger Sub II and the Company Representative, dated March 18, 2024 (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on March 18, 2024).

2.3#
Agreement an d Plan of Merger , dated as of June 2, 2025, by and among Viper , Viper LLC, New Cobra Pubco, Inc. , Cobra Members Sub, Inc., Scorpion Me rger Sub, Inc., Sitio Royalties Corp. and Sitio Royalties Operating Partnership, LP (incorporated by reference to Exhibit 2 .1 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed on June 4 , 202 5 ) .

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 Fifth Amended and Restated Bylaws of the Company, adopted as of September 18, 2024 (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 18, 2024).

4.1 Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

4.2 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 Viper Energy, Inc. on July 23, 2025).

4.3 First Supplemental Indenture, dated as of July 23, 2025, by and among Viper Energy Partners LLC, Viper Energy, Inc. and Computershare Trust Company, National Association, as Trustee (including the form of the Notes) (incorporated by reference to Exhibit 4.2 of the Current Report on Form 8-K (File No. 001-36505) filed by Viper Energy, Inc. on July 23, 2025).

10.1+
Diamondback Energy, Inc. Amended and Restated Senior Management Severance Plan, adopted effective as of April 6, 2025 (including a form of participation agreement attached thereto as Schedule C) (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No 001-35700, filed by the Company with the SEC on May 7, 2025).

10.2 Sixteenth Amendment to Second Amended and Restated Credit Agreement, dated as of June 12 , 2025, by and among the Company, as borrower, the lenders and other parties party thereto, and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10. 1 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on June 12 , 2025).

10.3 Credit Agreement, dated as of Ju ne 12, 2025 , by and among, Viper Energy Partners LLC, as borrower, Viper Energy , Inc. , as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File 001-36505) filed by Viper Energy , Inc. on June 12, 2025 ).

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Exhibit Number Description
10.4 Term Loan Credit Agreement, dated as of July 23, 2025, by and among Viper Energy Partners LLC, Viper Energy, Inc., 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 Viper Energy, Inc. on July 23, 2025).

22.1 List of Issuers and Guarantor Subsidiaries (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 June 30, 2025, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement 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).

______________

+ Management contract, compensatory plan or arrangement.

*
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.
# Schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K promulgated by the SEC. The Registrant agrees to furnish supplementally a copy of any omitted schedule or exhibit to the SEC upon request.

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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: August 6, 2025 /s/ Kaes Van’t Hof

Kaes Van’t Hof

Chief Executive Officer
(Principal Executive Officer)

Date: August 6, 2025 /s/ Jere W. Thompson III

Jere W. Thompson III

Chief Financial Officer
(Principal Financial Officer)

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