filings.toolsItem 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2024. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Part II. Item 1A. Risk Factors and Cautionary Statement Regarding Forward-Looking Statements**.
Overview
We are an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. As discussed in Note 1—Description of the Business and Basis of Presentation and Note 18—Segment Information of the notes to the condensed consolidated financial statements, as of March 31, 2025, we have one reportable segment, the upstream segment.
First Quarter 2025 Financial and Operating Highlights
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Recorded net income of $1.4 billion.
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Increased our annual base dividend to $4.00 per share of common stock, paid dividends to stockholders of $290 million during the first quarter of 2025 and declared a base cash dividend payable in the second quarter of 2025 of $1.00 per share of common stock.
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Repurchased $575 million of our common stock, excluding excise taxes, and had approximately $2.1 billion available for future repurchases under our common stock repurchase program at March 31, 2025.
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Our cash operating costs were $10.48 per BOE, including lease operating expenses of $5.33 per BOE, cash general and administrative expenses of $0.72 per BOE and production and ad valorem taxes of $2.98 per BOE and gathering, processing and transportation expenses of $1.45 per BOE.
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Our average production was 850.7 MBOE/d.
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Drilled 124 gross horizontal wells in the Midland Basin and two gross horizontal wells in the Delaware Basin, and turned 123 gross operated horizontal wells (116 in the Midland Basin and seven in the Delaware Basin) to production.
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Cash capital expenditures, excluding acquisitions, of $942 million.
Transactions and Recent Developments
Acquisitions and Divestitures
2025 Drop Down Transaction
On May 1, 2025, our wholly owned subsidiary EER LP divested the Endeavor Subsidiaries to Viper and Viper LLC in exchange for consideration consisting of (i) 1.0 billion in cash, and (ii) the issuance of 69.63 million Viper LLC units and an equal number of shares of Viper’s Class B common stock (which securities are exchangeable for an equal number of Viper’s Class A common stock), subject to transaction costs and certain customary post-closing adjustments. Viper funded the cash consideration for the 2025 Drop Down with a portion of the proceeds from the Viper 2025 Equity Offering and borrowings under Viper LLC’s credit agreement. The mineral and royalty interests held and divested by the Endeavor Subsidiaries at closing of the 2025 Drop Down represent approximately 22,847 net royalty acres located primarily in the Permian Basin. The Endeavor Subsidiaries sold in the 2025 Drop Down were acquired by us in the recently completed Endeavor Acquisition. On May 5, 2025, we used the cash proceeds received from the 2025 Drop Down to repay in full and terminate the $900 million Tranche A Loans.
Double Eagle Acquisition
On April 1, 2025, we completed the Double Eagle Acquisition for consideration of $3.0 billion in cash and approximately 6.84 million shares of our common stock, subject to transaction costs and certain customary post-closing
adjustments. The Double Eagle Acquisition consists of approximately 67,700 gross (40,000 net) acres, which are primarily located in the Midland Basin, and approximately 407 gross (342 net) horizontal locations in primary development targets. We funded the cash portion of the Double Eagle Acquisition through a combination of proceeds from the 2035 Notes, proceeds from the 2025 Term Loan Agreement and borrowings under our credit facility.
Retirement of Notes
In the second quarter of 2025, we opportunistically repurchased principal amounts of $111 million of our 4.400% Senior Notes due 2051, $89 million of our 4.250% Senior Notes due 2052 and $20 million of our 5.750% Senior Notes due 2054 in open market transactions for total cash consideration of $167 million, including accrued interest paid, at an average of 75.3% of par value.
See Note 17—Subsequent Events of the notes to the condensed consolidated financial statements for further discussion of the transactions above.
Capital Transactions
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 on April 1, 2025.
2035 Notes Offering
On March 20,2025, we issued the 2035 Notes for net proceeds of $1.2 billion, after underwriters’ discounts and transaction costs, which we used to fund a portion of the cash consideration for the Double Eagle Acquisition.
See Note 9—Debt of the notes to the condensed consolidated financial statements for further discussion of the transactions above.
Viper 2025 Equity Offering
On February 3, 2025, Viper completed an underwritten public offering of approximately 28.34 million shares of its Class A common stock, which included 3.70 million shares issued pursuant to an option to purchase additional shares of its Class A common stock granted to the underwriters at a price to the public of $44.50 per share for total net proceeds to Viper of approximately 1.2 billion, after the underwriters’ discount and estimated transaction costs.
See Note 10—Stockholders' Equity and Earnings (Loss) Per Share 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 three months ended March 31, 2025 and 2024, WTI prices averaged $71.42 and $76.91 per Bbl, respectively, and Henry Hub prices averaged $3.87 and $2.10 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 March 31, 2025, we had approximately 859,484 net acres, which primarily consisted of approximately 737,736 net acres in the Midland Basin and 121,748 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 March 31, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||
| Drilled | Completed**(1)** | ||||||||||||||||||||||||||||||||||||||||||||||
| Area: | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||||||||
| Midland Basin | 124 | 116 | 116 | 112 | |||||||||||||||||||||||||||||||||||||||||||
| Delaware Basin | 2 | 2 | 7 | 7 | |||||||||||||||||||||||||||||||||||||||||||
| Total | 126 | 118 | 123 | 119 |
(1)The average lateral length for the wells completed during the first quarter of 2025 was 11,978 feet. Operated completions during the first quarter of 2025 consisted of 30 Wolfcamp A wells, 28 Lower Spraberry wells, 22 Wolfcamp B wells, 17 Jo Mill wells, eight Middle Spraberry wells, four Dean wells, four Barnett wells, three Third Bone Spring wells, three Wolfcamp D wells, two Second Bone Spring wells and two Upper Spraberry wells.
As of March 31, 2025, we operated the following wells:
| As of March 31, 2025 | |||||||||||||||||||||||||||||||||||
| Vertical Wells | Horizontal Wells | Total | |||||||||||||||||||||||||||||||||
| Area: | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||
| Midland Basin | 4,411 | 4,181 | 4,369 | 4,100 | 8,780 | 8,281 | |||||||||||||||||||||||||||||
| Delaware Basin | 172 | 152 | 507 | 469 | 679 | 621 | |||||||||||||||||||||||||||||
| Total | 4,583 | 4,333 | 4,876 | 4,569 | 9,459 | 8,902 |
As of March 31, 2025, we held interests in 31,344 gross (9,290 net) wells, including 2,390 gross (367 net) wells in which we have a non-operated working interest.
Guidance
Given recent weakness in commodity prices, we have reduced our activity levels and lowered our capital budget to prioritize free cash flow generation. We believe that our revised development plan enhances capital efficiency and provides flexibility to adjust our activity levels up or down, as appropriate, if commodity prices strengthen or weaken further.
The following table presents our updated estimates of certain financial and operating results for the full year of 2025 and the second quarter of 2025:
| 2025 Guidance | |||||
| Net production - MBOE/d | 857 - 900 (from 883 - 909) | ||||
| Oil production - MBO/d | 480 - 495 (from 485 - 498) | ||||
| Q2 2025 oil production - MBO/d (total - MBOE/d) | 485 - 500 (866 - 900) | ||||
| (Unit costs $/BOE): | |||||
| Lease operating expenses, including workovers | $5.65 - $6.05 (from $5.90 - $6.30) | ||||
| General and administrative expenses - cash | $0.60 - $0.75 | ||||
| Non-cash stock-based compensation | $0.25 - $0.35 | ||||
| Depreciation, depletion, amortization and accretion | $14.00 - $15.00 | ||||
| Interest expense (net of interest income) | $0.40 - $0.65 (from $0.25 - $0.50) | ||||
| Gathering, processing and transportation | $1.40 - $1.60 (from $1.20 - $1.40) | ||||
| Production and ad valorem taxes (% of revenue) | ~7% | ||||
| Corporate tax rate (% of pre-tax income) | 23% | ||||
| Cash tax rate (% of pre-tax income) | 19% - 22% (from 17% - 20%) | ||||
| Q2 2025 cash taxes (in millions)(1) | $340 - $400 |
(1) Includes approximately $170 million of cash taxes related to the Viper dropdown transaction.
Results of Operations
Comparison of the Three Months Ended March 31, 2025 and December 31, 2024
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 March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| March 31, 2025 | December 31, 2024 | ||||||||||
| Revenues (In millions): | |||||||||||
| Oil sales | $ | 3,039 | $ | 3,042 | |||||||
| Natural gas sales | 212 | 51 | |||||||||
| Natural gas liquid sales | 406 | 378 | |||||||||
| Total oil, natural gas and natural gas liquid revenues | $ | 3,657 | $ | 3,471 | |||||||
| Production Data: | |||||||||||
| Oil (MBbls) | 42,835 | 43,785 | |||||||||
| Natural gas (MMcf) | 100,578 | 107,249 | |||||||||
| Natural gas liquids (MBbls) | 16,961 | 19,615 | |||||||||
| Combined volumes (MBOE)(1) | 76,559 | 81,275 | |||||||||
| Daily oil volumes (BO/d) | 475,944 | 475,924 | |||||||||
| Daily combined volumes (BOE/d) | 850,656 | 883,424 | |||||||||
| Average Prices: | |||||||||||
| Oil ($ per Bbl) | $ | 70.95 | $ | 69.48 | |||||||
| Natural gas ($ per Mcf) | $ | 2.11 | $ | 0.48 | |||||||
| Natural gas liquids ($ per Bbl) | $ | 23.94 | $ | 19.27 | |||||||
| Combined ($ per BOE) | $ | 47.77 | $ | 42.71 | |||||||
| Oil, hedged ($ per Bbl)(2) | $ | 70.06 | $ | 68.72 | |||||||
| Natural gas, hedged ($ per Mcf)(2) | $ | 3.34 | $ | 0.82 | |||||||
| Natural gas liquids, hedged ($ per Bbl)(2) | $ | 23.94 | $ | 19.27 | |||||||
| Average price, hedged ($ per BOE)(2) | $ | 48.89 | $ | 42.76 |
(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 March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| March 31, 2025 | December 31, 2024 | ||||||||||
| Oil (MBbls) | 56 | % | 54 | % | |||||||
| Natural gas (MMcf) | 22 | 22 | |||||||||
| Natural gas liquids (MBbls) | 22 | 24 | |||||||||
| 100 | % | 100 | % |
| Three Months Ended March 31, 2025 | Three Months Ended December 31, 2024 | ||||||||||||||||||||||||||||||||||||||||||||||
| Midland Basin | Delaware Basin | Other | Total | Midland Basin | Delaware Basin | Other | Total | ||||||||||||||||||||||||||||||||||||||||
| Production Data: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) | 39,341 | 3,460 | 34 | 42,835 | 39,134 | 4,603 | 48 | 43,785 | |||||||||||||||||||||||||||||||||||||||
| Natural gas (MMcf) | 90,341 | 9,961 | 276 | 100,578 | 93,596 | 13,318 | 335 | 107,249 | |||||||||||||||||||||||||||||||||||||||
| Natural gas liquids (MBbls) | 15,769 | 1,155 | 37 | 16,961 | 17,551 | 2,041 | 23 | 19,615 | |||||||||||||||||||||||||||||||||||||||
| Total (MBOE) | 70,167 | 6,275 | 117 | 76,559 | 72,284 | 8,864 | 127 | 81,275 |
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 first quarter of 2025 increased by $186 million to $3.7 billion compared to the fourth quarter of 2024. The net increase was due to an additional $306 million related to improved average prices received for our oil, natural gas and natural gas liquids production, which was partially offset by a $120 million decrease attributable to the 6% decline in our combined production volumes.
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 March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| (In millions) | March 31, 2025 | December 31, 2024 | |||||||||
| Sales of purchased oil | $ | 374 | $ | 225 | |||||||
| Purchased oil expense | 382 | 225 | |||||||||
| Net sales of purchased oil | $ | (8) | $ | — |
Other Revenues. The following table presents other insignificant revenue for the three months ended March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| (In millions) | March 31, 2025 | December 31, 2024 | |||||||||
| Other operating income | $ | 17 | $ | 15 |
Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||||||||||||||
| March 31, 2025 | December 31, 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| Lease operating expenses | $ | 408 | $ | 5.33 | $ | 461 | $ | 5.67 |
Lease operating expenses decreased in total and on a per BOE basis for the first quarter of 2025 compared to the fourth quarter of 2024 primarily due to (i) a $38 million reduction in cost estimates related to producing properties acquired in the Endeavor Acquisition, (ii) a $7 million decrease due to applying a contingent volume discount for water services from Deep Blue in the first quarter of 2025, (iii) a $6 million reduction in well workover expenses, and (iv) other individually insignificant changes.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||||||||||||||||||||||||||
| March 31, 2025 | December 31, 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 | $ | 171 | $ | 2.23 | 4.7 | % | $ | 168 | $ | 2.07 | 4.8 | % | |||||||||||||||||||||||
| Ad valorem taxes | 57 | 0.75 | 1.5 | 57 | 0.70 | 1.7 | |||||||||||||||||||||||||||||
| Total production and ad valorem expense | $ | 228 | $ | 2.98 | 6.2 | % | $ | 225 | $ | 2.77 | 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 fourth quarter of 2024 to the first 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 in total and per BOE during the first quarter of 2025 compared to the fourth quarter of 2024.
Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expense for the three months ended March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||||||||||||||
| March 31, 2025 | December 31, 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| Gathering, processing and transportation | $ | 111 | $ | 1.45 | $ | 95 | $ | 1.17 |
The increase in gathering, processing and transportation expenses is primarily attributable to (i) a $6 million increase from the restructuring of certain sales contracts acquired from Endeavor in the first quarter of 2025, for which gathering and transportation charges were previously recorded as a reduction to revenue, (ii) increases in the contractual pricing of our gathering, processing and transportation costs, and (iii) 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 March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| (In millions, except BOE amounts) | March 31, 2025 | December 31, 2024 | |||||||||
| Depletion of proved oil and natural gas properties | $ | 1,065 | $ | 1,121 | |||||||
| Depreciation and amortization of other property and equipment | 23 | 25 | |||||||||
| Other amortization | — | 2 | |||||||||
| Asset retirement obligation accretion | 9 | 8 | |||||||||
| Depreciation, depletion, amortization and accretion | $ | 1,097 | $ | 1,156 | |||||||
| Oil and natural gas properties depletion rate per BOE | $ | 13.91 | $ | 13.79 | |||||||
| Depreciation, depletion, amortization and accretion per BOE | $ | 14.33 | $ | 14.22 |
Depletion of proved oil and natural gas properties decreased by $56 million for the first quarter of 2025 compared to the fourth quarter of 2024. This change was comprised of a $65 million decrease due to the decline in production volumes, and a $9 million increase due to a slightly higher depletion rate in the first quarter of 2025.
General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||||||||||||||
| March 31, 2025 | December 31, 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| General and administrative expenses | $ | 55 | $ | 0.72 | $ | 56 | $ | 0.69 | |||||||||||||||
| Non-cash stock-based compensation | 18 | 0.24 | 16 | 0.20 | |||||||||||||||||||
| Total general and administrative expenses | $ | 73 | $ | 0.96 | $ | 72 | $ | 0.89 |
Other Operating Costs and Expenses. The following table shows other operating costs and expenses for the three months ended March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| (In millions) | March 31, 2025 | December 31, 2024 | |||||||||
| Merger and integration expenses | $ | 37 | $ | 30 | |||||||
| Other operating expenses | $ | 39 | $ | 35 |
Merger and integration expenses for the first quarter of 2025 were primarily comprised of $23 million of employee severance costs and $2 million of IT and other integration service costs incurred in connection with the Endeavor Acquisition, $10 million in advisory and legal fees incurred as part of the TRP Exchange, and other individually insignificant costs. Merger and integration expenses for the three months ended December 31, 2024 were primarily comprised of employee severance costs related to 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 the TRP Exchange, respectively.
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 March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| (In millions) | March 31, 2025 | December 31, 2024 | |||||||||
| Gain (loss) on derivative instruments, net | $ | 226 | $ | 36 | |||||||
| Net cash received (paid) on settlements | $ | 85 | $ | (15) |
The change in gain (loss) on derivative instruments for the first quarter of 2025 compared to the fourth quarter of 2024 primarily reflects (i) an increase of $87 million in cash received on the settlement of natural gas contracts, (ii) an increase of $59 million in the value of our unsettled oil and natural gas contracts due to a decline in market prices for oil and natural gas compared to our contract prices, (iii) a $26 million increase in the value of our interest rate swap contracts driven by a decline in expected future interest rates, (iv) a $19 million decrease in cash paid on the settlement of interest rate swaps, and (v) 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 three months ended March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| (In millions) | March 31, 2025 | December 31, 2024 | |||||||||
| Interest expense, net | $ | (40) | $ | (34) | |||||||
| Other income (expense), net | $ | 27 | $ | (7) | |||||||
| Income (loss) from equity investments, net | $ | 8 | $ | (2) |
The increase in interest expense, net for the first quarter of 2025 compared to the fourth quarter of 2024 primarily consists of (i) a $15 million decrease in capitalized interest costs, which increased interest expense, and (ii) a $3 million increase in interest expense on senior notes primarily related to the newly issued 2035 Notes. These increases were partially offset by (i) a $5 million increase in interest income due to holding proceeds from the 2035 Notes in short-term interest bearing accounts until the closing date of the Double Eagle Acquisition, (ii) a $3 million decrease in interest expense on our Tranche A loans due to a $100 million repayment of principal in the fourth quarter of 2024, (iii) a $2 million decrease in interest expense on Viper’s revolving credit facility due to a lower average quarterly outstanding balance during the first 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 first quarter of 2025 compared to the fourth quarter of 2024 is primarily due to a gain of $42 million related to the receipt of additional proceeds in connection with the WTG Midstream Transaction, which was partially offset by a $10 million 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.
Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended March 31, 2025 and December 31, 2024:
| Three Months Ended | |||||||||||
| (In millions) | March 31, 2025 | December 31, 2024 | |||||||||
| Provision for (benefit from) income taxes | $ | 403 | $ | 115 |
The change in our income tax provision for the first quarter of 2025 compared to the fourth quarter of 2024 was primarily due to the increase in pre-tax income between the periods which resulted largely from changes in revenues, operating expenses, and the gain on derivative contracts as discussed above. In addition to the increase in pre-tax income for the first quarter of 2025, the income tax provision for the fourth quarter of 2024 included a partially offsetting net tax benefit of $156 million due to the release of Viper’s remaining valuation allowance. See Note 12—Income Taxes of the notes to the condensed consolidated financial statements for further discussion of our income tax expense.
Comparison of the Three Months Ended March 31, 2025 and 2024
The following table sets forth selected operating data for the three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Revenues (In millions): | |||||||||||
| Oil sales | $ | 3,039 | $ | 1,867 | |||||||
| Natural gas sales | 212 | 50 | |||||||||
| Natural gas liquid sales | 406 | 184 | |||||||||
| Total oil, natural gas and natural gas liquid revenues | $ | 3,657 | $ | 2,101 | |||||||
| Production Data: | |||||||||||
| Oil (MBbls) | 42,835 | 24,874 | |||||||||
| Natural gas (MMcf) | 100,578 | 50,602 | |||||||||
| Natural gas liquids (MBbls) | 16,961 | 8,653 | |||||||||
| Combined volumes (MBOE)(1) | 76,559 | 41,961 | |||||||||
| Daily oil volumes (BO/d) | 475,944 | 273,341 | |||||||||
| Daily combined volumes (BOE/d) | 850,656 | 461,110 | |||||||||
| Average Prices: | |||||||||||
| Oil ($ per Bbl) | $ | 70.95 | $ | 75.06 | |||||||
| Natural gas ($ per Mcf) | $ | 2.11 | $ | 0.99 | |||||||
| Natural gas liquids ($ per Bbl) | $ | 23.94 | $ | 21.26 | |||||||
| Combined ($ per BOE) | $ | 47.77 | $ | 50.07 | |||||||
| Oil, hedged ($ per Bbl)(2) | $ | 70.06 | $ | 74.13 | |||||||
| Natural gas, hedged ($ per Mcf)(2) | $ | 3.34 | $ | 1.36 | |||||||
| Natural gas liquids, hedged ($ per Bbl)(2) | $ | 23.94 | $ | 21.26 | |||||||
| Average price, hedged ($ per BOE)(2) | $ | 48.89 | $ | 49.97 |
(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 three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Oil (MBbls) | 56 | % | 59 | % | |||||||
| Natural gas (MMcf) | 22 | 20 | |||||||||
| Natural gas liquids (MBbls) | 22 | 21 | |||||||||
| 100 | % | 100 | % |
| Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | ||||||||||||||||||||||||||||||||||||||||||||||
| Midland Basin | Delaware Basin | Other | Total | Midland Basin | Delaware Basin | Other | Total | ||||||||||||||||||||||||||||||||||||||||
| Production Data: | |||||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) | 39,341 | 3,460 | 34 | 42,835 | 20,055 | 4,768 | 51 | 24,874 | |||||||||||||||||||||||||||||||||||||||
| Natural gas (MMcf) | 90,341 | 9,961 | 276 | 100,578 | 37,494 | 12,894 | 214 | 50,602 | |||||||||||||||||||||||||||||||||||||||
| Natural gas liquids (MBbls) | 15,769 | 1,155 | 37 | 16,961 | 6,643 | 1,990 | 20 | 8,653 | |||||||||||||||||||||||||||||||||||||||
| Total (MBOE) | 70,167 | 6,275 | 117 | 76,559 | 32,947 | 8,907 | 107 | 41,961 |
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 three months ended March 31, 2025 increased by $1.6 billion, or 74%, to $3.7 billion from the same period in 2024 primarily due to the 82% growth in our combined production volumes.
Approximately 73% of the increase in our combined production volumes is attributable to the Endeavor 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 three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Sales of purchased oil | $ | 374 | $ | 116 | |||||||
| Purchased oil expense | 382 | 117 | |||||||||
| Net sales of purchased oil | $ | (8) | $ | (1) |
Other Revenues. The following table shows the other insignificant revenues for the three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Other operating income | $ | 17 | $ | 10 |
Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| Lease operating expenses | $ | 408 | $ | 5.33 | $ | 255 | $ | 6.08 |
Lease operating expenses increased in total for the three months ended March 31, 2025 compared to the same period in 2024 primarily due to costs associated with operating wells acquired as part of the Endeavor Acquisition.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||||||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Percentage of oil, natural gas and natural gas liquids revenue | Amount | Per BOE | Percentage of oil, natural gas and natural gas liquids revenue | |||||||||||||||||||||||||||||
| Production taxes | $ | 171 | $ | 2.23 | 4.7 | % | $ | 82 | $ | 1.96 | 3.9 | % | |||||||||||||||||||||||
| Ad valorem taxes | 57 | 0.75 | 1.5 | 37 | 0.88 | 1.8 | |||||||||||||||||||||||||||||
| Total production and ad valorem expense | $ | 228 | $ | 2.98 | 6.2 | % | $ | 119 | $ | 2.84 | 5.7 | % |
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes increased by $89 million compared to the same period in 2024, due primarily to (i) $70 million in additional taxes related to production from the Endeavor Acquisition, and (ii) a refund recorded during the three months ended March 31, 2024 of $17 million 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 three months ended March 31, 2025 as compared to the same period in 2024 increased by $20 million, primarily due to $28 million of additional taxes incurred on properties from the Endeavor Acquisition, which was partially offset by an $8 million decrease caused by a decline 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 three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| Gathering, processing and transportation | $ | 111 | $ | 1.45 | $ | 77 | $ | 1.84 |
The increase in gathering, processing and transportation expenses for the three months ended March 31, 2025 compared to the same period in 2024 is attributable primarily to (i) $7 million from the restructuring in 2025 of certain revenue contracts acquired from Endeavor, for which gathering and transportation charges were previously recorded as a reduction to revenue, and (ii) growth in legacy production volumes.
Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| (In millions, except BOE amounts) | 2025 | 2024 | |||||||||
| Depletion of proved oil and natural gas properties | $ | 1,065 | $ | 452 | |||||||
| Depreciation and amortization of other property and equipment | 23 | 12 | |||||||||
| Other amortization | — | 2 | |||||||||
| Asset retirement obligation accretion | 9 | 3 | |||||||||
| Depreciation, depletion, amortization and accretion | $ | 1,097 | $ | 469 | |||||||
| Oil and natural gas properties depletion rate per BOE | $ | 13.91 | $ | 10.77 | |||||||
| Depreciation, depletion, amortization and accretion per BOE | $ | 14.33 | $ | 11.18 |
The increase in depletion of proved oil and natural gas properties of $613 million for the three months ended March 31, 2025 as compared to the same period in 2024 consists primarily of $373 million from growth in production volumes and $240 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 and, to a lesser extent, Viper’s Tumbleweed Acquisitions subsequent to the first quarter of 2024.
Additionally, depreciation and amortization of other property and equipment increased as a result of the acquisition of other property and equipment in connection with the Endeavor Acquisition.
General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| (In millions, except per BOE amounts) | Amount | Per BOE | Amount | Per BOE | |||||||||||||||||||
| General and administrative expenses | $ | 55 | $ | 0.72 | $ | 32 | $ | 0.76 | |||||||||||||||
| Non-cash stock-based compensation | 18 | 0.24 | 14 | 0.34 | |||||||||||||||||||
| Total general and administrative expenses | $ | 73 | $ | 0.96 | $ | 46 | $ | 1.10 |
General and administrative expenses increased for the three months ended March 31, 2025 compared to the same period in 2024 primarily due to an $18 million increase in employee compensation and benefit costs related to increasing headcount and annual compensation adjustments, and a $9 million increase in software costs.
Other Operating Costs and Expenses. The following table shows the other operating costs and expenses for the three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Merger and integration expenses | $ | 37 | $ | 12 | |||||||
| Other operating expenses | $ | 39 | $ | 14 |
Merger and integration expenses for the three months ended March 31, 2025 were primarily comprised of (i) $23 million of employee severance costs and $2 million of IT 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. Merger and integration expenses for the three months ended March 31, 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 three months ended March 31, 2025 compared to the same period in 2024 primarily resulted from (i) a $16 million increase in midstream service costs largely associated with the additional production from the Endeavor Acquisition, (ii) a $4 million loss on the sale of non-core property, plant and equipment acquired from Endeavor, and (iii) 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 three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Gain (loss) on derivative instruments, net | $ | 226 | $ | (48) | |||||||
| Net cash received (paid) on settlements | $ | 85 | $ | (4) |
The change from a loss to a gain on derivative instruments for the three months ended March 31, 2025 compared to the same period in 2024 primarily reflects (i) a $140 million increase in the value of our unsettled commodity derivative contracts primarily due to a $117 million increase in the value of our natural gas contracts, (ii) a $106 million increase in cash received on the settlement of our natural gas contracts, and (iii) a $43 million increase in the value of our unsettled interest rate swap contracts primarily due to a decline in expected future interest rates. These gains were partially offset by paying an additional $16 million on settlements of oil our contracts in the first quarter of 2025. 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 three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Interest expense, net | $ | (40) | $ | (39) | |||||||
| Other income (expense), net | $ | 27 | $ | (3) | |||||||
| Gain (loss) on extinguishment of debt | $ | — | $ | 2 | |||||||
| Income (loss) from equity investments, net | $ | 8 | $ | 2 |
Interest expense, net increased by $1 million for the three months ended March 31, 2025 compared to the same period in 2024. This decrease primarily consisted of (i) a $79 million increase in interest expense incurred on senior notes related to the issuance of the April 2024 Notes, and to a lesser extent, the 2035 Notes, and (ii) a $13 million increase in interest expense incurred on our Tranche A Loans. These increases were largely offset by (i) an additional $82 million in capitalized interest costs, which reduce interest expense, (ii) a $7 million reduction in the amortization of debt issuance costs primarily related to the remaining debt issuance costs on 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 three months ended March 31, 2025 increased compared to the three months ended March 31, 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 loss of $10 million on the remeasurement of an investment recorded at fair value and other individually insignificant items.
Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended March 31, 2025 and 2024:
| Three Months Ended March 31, | |||||||||||
| (In millions) | 2025 | 2024 | |||||||||
| Provision for (benefit from) income taxes | $ | 403 | $ | 223 |
The change in our income tax provision for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to the increase in pre-tax income resulting largely from higher revenues from oil and natural gas liquids, 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.
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 March 31, 2025, we had approximately $3.8 billion of liquidity consisting of $1.3 billion in standalone cash and cash equivalents and $2.5 billion available under our credit facility. We further had $1.5 billion available under the 2025 Term Loan Agreement, which was fully drawn on April 1, 2025 to partially fund the Double Eagle Acquisition. As discussed above, due to recent weakness in commodity prices, we have reduced activity levels and lowered our capital budget for 2025 to $3.40 billion to $3.80 billion to prioritize free cash flow generation.
At March 31, 2025, we had approximately $900 million of Tranche A Loans and $14 million of senior notes maturing in the next 12 months. On May 5, 2025, the Company used the cash proceeds received from the 2025 Drop Down to repay in full and terminate the $900 million Tranche A Loans.
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. 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 three months ended March 31, 2025 and 2024 are presented below:
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In millions) | |||||||||||
| Net cash provided by (used in) operating activities | $ | 2,355 | $ | 1,334 | |||||||
| Net cash provided by (used in) investing activities | (1,653) | (751) | |||||||||
| Net cash provided by (used in) financing activities | 1,175 | (269) | |||||||||
| Net increase (decrease) in cash | $ | 1,877 | $ | 314 |
Operating Activities
The increase in operating cash flows for the three months ended March 31, 2025 compared to the same period in 2024 primarily resulted from (i) $1.6 billion in additional revenue, excluding sales of purchased oil, and (ii) an increase of $89 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 $369 million, (ii) an increase of $250 million in cash paid for taxes, and (iii) fluctuations in other working capital balances due primarily to the timing of when collections were made on accounts receivable and payments were made on accounts payable. See “—**Results of Operations” for discussion of significant changes in our revenues and expenses.
Investing Activities
The majority of our net cash used in investing activities during the three months ended March 31, 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 including the $208 million escrow deposit for the Double Eagle Acquisition.
Capital Expenditure Activities
Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In millions) | |||||||||||
| Operated drilling and completion additions to oil and natural gas properties(1) | $ | (864) | $ | (572) | |||||||
| Capital workovers, non-operated additions to oil and natural gas properties and science | (21) | (8) | |||||||||
| Infrastructure, environmental and midstream additions | (57) | (29) | |||||||||
| Total | $ | (942) | $ | (609) |
(1) See “—Transactions and Recent Developments—Upstream Operations” above for additional detail on wells drilled and turned to production during the three and three months ended March 31, 2025 and 2024.
Financing Activities
During the three months ended March 31, 2025, net cash provided by financing activities was primarily attributable to $1.2 billion of proceeds from the issuance of the 2035 Notes and $1.2 billion in proceeds from the Viper 2025 Equity Offering.
These cash inflows were partially offset by (i) $575 million of repurchases as part of the share repurchase program, (ii) $290 million of dividends paid to stockholders, (iii) $261 million in repayments on our credit facilities, net of borrowings, (iv) $95 million in dividends paid to non-controlling interest, (v) and various other individually insignificant costs.
During the three months ended March 31, 2024, net cash used in financing activities was primarily attributable to (i) $548 million of dividends paid to stockholders, (ii) $44 million in dividends to non-controlling interest, (iii) $42 million of repurchases as part of the share repurchase programs, (iv) $34 million in cash paid for tax withholdings on vested employee stock awards (v) $33 million of debt issuance costs primarily associated with the Term Loan Agreement and Bridge Facility, and (vi) $25 million paid for the retirement of principal outstanding on certain senior notes. These cash outflows were partially offset by $451 million in proceeds from the public offering of Viper’s Class A common stock and an additional $10 million in borrowings under credit facilities, net of repayments.
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. Further, the 2025 Term Loan Agreement and net proceeds from the 2035 Notes were also available to finance the cash portion of the Double Eagle Acquisition as of March 31, 2025. 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 March 31, 2025, our debt, including the debt of Viper, consisted of approximately $13.2 billion in aggregate outstanding principal amount of senior notes and $900 million in aggregate outstanding borrowings under the Tranche A Loans. On May 5, 2025, the Company used the cash proceeds received from the 2025 Drop Down to repay in full and terminate the $900 million Tranche A Loans.
As of March 31, 2025, the maximum credit amount available under our credit agreement was $2.5 billion, with no outstanding borrowings and $2.5 billion available for future borrowings. Our credit agreement matures on June 2, 2029.
As of March 31, 2025, the maximum credit amount available under our 2025 Term Loan Agreement was $1.5 billion, which was drawn in a single borrowing on April 1, 2025 to fund a portion of the cash consideration for the Double Eagle Acquisition. Our 2025 Term Loan Agreement matures on the second anniversary of the initial funding date.
2035 Notes Offering
On March 20, 2025, we issued the 2035 Notes for net proceeds of $1.2 billion, after underwriters’ discounts and transaction costs, which we used to fund a portion of the cash consideration for the Double Eagle Acquisition.
Viper LLC’s Credit Agreement
The Viper LLC credit agreement, as amended, matures on September 22, 2028 and provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $1.3 billion and an elected commitment amount of $1.3 billion. As of March 31, 2025, the Viper LLC credit agreement had no outstanding borrowings and $1.3 billion available for future borrowings.
On May 1, 2025, we completed the 2025 Drop Down with Viper as discussed in Note 17— Subsequent Events of the notes to the condensed consolidated financial statements. Approximately $255 million of the cash consideration for this transaction was funded through borrowings under the Viper LLC credit agreement, reducing the amount that remained available for future borrowings under this facility to $995 million as of May 1, 2025.
For additional discussion of our debt as of March 31, 2025, see Note 9—Debt of the notes to the condensed consolidated financial statements.
Viper 2025 Equity Offering
During the first quarter of 2025, Viper completed the Viper 2025 Equity Offering for total net proceeds of approximately $1.2 billion, after the underwriters’ discount and transaction costs. For additional discussion of the Viper 2025 Equity Offering, see Note 10—Stockholders' Equity and Earnings (Loss) Per Share 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, Tranche A Loans, and senior notes, (iii) payments of other contractual obligations, (iv) cash used to pay for dividends and repurchases of securities, (v) and the cash portion of the Double Eagle Acquisition.
2025 Capital Spending Plan
Our board of directors has approved our revised 2025 capital budget for drilling, midstream, infrastructure and environmental expenditures, which takes into consideration recent weakness in commodity prices and our reduced activity levels to prioritize free cash flow generation. Our revised capital budget for the full year 2025 is approximately $3.40 billion to $3.80 billion, including $2.78 billion to $3.09 billion for operated horizontal drilling and completions, $280 million to $320 million for non-operated activity and capital workovers and $340 million to $390 million spent on infrastructure, midstream and environmental capital expenditures. We currently expect to drill approximately 385 to 435 gross (349 to 395 net) horizontal wells and complete approximately 475 to 550 gross (444 to 514 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 16 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 and 2029, and $366 million cumulatively between 2030 and 2035.
Retirement of Notes
In the second quarter of 2025, we opportunistically repurchased $220 million in principal amounts of our senior notes in open market transactions for total cash consideration of $167 million, at an average of 75.3% of par value. We may continue to opportunistically repurchase principal amounts of our and Viper’s senior notes in future periods.
See Note 17—Subsequent Events of the notes to the condensed consolidated financial statements for further discussion of these transactions.
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 May 1, 2025, our board of directors declared a base cash dividend for the first 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 September 18, 2024, our board of directors approved an increase in our common stock repurchase program from $4.0 billion to $6.0 billion, excluding excise tax. Since the inception of the stock repurchase program, we repurchased an aggregate of 30.2 million shares of our common stock for a total cost of $4.2 billion, excluding excise tax, as of May 2, 2025. 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 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.
| March 31, 2025 | December 31, 2024 | ||||||||||
| Summarized Balance Sheets: | (In millions) | ||||||||||
| Assets: | |||||||||||
| Current assets | $ | 1,979 | $ | 933 | |||||||
| Property and equipment, net | $ | 22,128 | $ | 21,795 | |||||||
| Other noncurrent assets | $ | 292 | $ | 32 | |||||||
| Liabilities: | |||||||||||
| Current liabilities | $ | 3,735 | $ | 2,943 | |||||||
| Intercompany accounts payable, non-guarantor subsidiary | $ | 3,418 | $ | 3,381 | |||||||
| Long-term debt | $ | 12,174 | $ | 10,978 | |||||||
| Other noncurrent liabilities | $ | 3,014 | $ | 2,979 |
| Three Months Ended March 31, 2025 | |||||
| Summarized Statement of Operations: | (In millions) | ||||
| Revenues | $ | 1,711 | |||
| Income (loss) from operations | $ | 442 | |||
| Net income (loss) | $ | 381 |
Critical Accounting Estimates
There have been no changes in our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024.
Recent Accounting Pronouncements
See Note 2—Summary of Significant Accounting Policies of the notes to the condensed consolidated financial statements for recent accounting pronouncements not yet adopted, if any.
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