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, 2025. 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, Part I. Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2025 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 17—Segment Information of the notes to the condensed consolidated financial statements, as of June 30, 2026, we have one reportable segment, the upstream segment. Second Quarter 2026 Financial and Operating Highlights •Recorded net income of $1.9 billion. •Our cash operating costs were $10.96 per BOE, including lease operating expenses of $5.96 per BOE, cash general and administrative expenses of $0.52 per BOE, production and ad valorem taxes of $3.26 per BOE and gathering, processing and transportation expenses of $1.22 per BOE. •Incurred cash capital expenditures, excluding acquisitions, of $996 million. •Paid dividends to stockholders, including dividend equivalent rights, of $311 million, or $1.10 per share, during the second quarter of 2026 and declared a base cash dividend payable in the third quarter of 2026 of $1.10 per share of common stock. •Repurchased $141 million of our common stock, excluding excise taxes. •Retired approximately $828 million in aggregate principal of our senior notes and $550 million in outstanding borrowings on our 2025 Term Loan, which was terminated upon repayment. •Our average production was 1,017.7 MBOE/d, surpassing the 1.0 million BOE/d milestone. •Drilled 97 gross horizontal wells in the Midland Basin and turned 168 gross operated horizontal wells in the Midland Basin to production. Transactions and Recent Developments Pending 2026 Drop Down On August 3, 2026, we entered into a definitive purchase agreement with Viper Energy Partners LP to divest certain mineral and royalty interests in exchange for 3.65 million Viper LLC Units and an equivalent number of shares of Viper’s Class B common stock (the pending “2026 Drop Down”), subject to transaction costs and certain customary post-closing adjustments. The pending 2026 Drop Down will be accounted for as a transaction between entities under common control with the acquired properties recorded at Diamondback’s historical carrying value in the Company’s condensed consolidated balance sheet. Increase in Stock Repurchase Program Authorization On July 30, 2026, our board of directors approved an increase in stock repurchase authorization under the Company’s existing stock repurchase program from $8.0 billion to $16.0 billion, excluding excise tax. 26 Table of Contents Viper Riverbend Acquisition On July 1, 2026, Viper and Viper Energy Partners LP acquired all of the equity interests of Riverbend for consideration consisting of approximately (i) $339 million in cash and (ii) 3.69 million shares of Viper’s Class A common stock, in each case, subject to customary post-closing adjustments. Commodity Prices Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Geopolitical global conflicts, tariffs or other trade barriers and any resulting trade tensions, regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, extreme weather conditions, changes in OPEC+ production levels and other substantially variable factors influence market conditions for these products. For example, as a result of the ongoing conflict in the Middle East, in 2026 the global crude oil market shifted from a supply-demand surplus to a deficit, materially reducing crude oil and refined products from the markets, and increasing benchmark crude oil prices. These factors are beyond our control and are difficult to predict. During the six months ended June 30, 2026 and 2025, WTI prices averaged $83.00 and $70.81 per Bbl, respectively, and Henry Hub prices averaged $3.20 and $3.69 per MMBtu, respectively. During the three and six months ended June 30, 2026, natural gas price realizations were adversely affected by widening basis differentials between natural gas prices at Waha Hub and prices at Henry Hub. The unfavorable differentials were primarily driven by regional natural gas takeaway constraints in the Permian Basin, which resulted in periods of negative pricing at Waha Hub. The Company expects the impact of these constraints to be reduced later in 2026 as its secured takeaway capacity is meaningfully increased through the execution of new contracts and expanded infrastructure build out in the region. However, realized prices are expected to continue to be influenced by, and subject to, future supply, demand, transportation availability and other market factors. Upstream Operations Our activities are primarily directed at the horizontal development of the Wolfcamp, Spraberry and Barnett 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, 2026, we had approximately 902,005 net acres in the Permian Basin, which included approximately 808,401 net acres in the Midland Basin and 93,604 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, 2026 Six Months Ended June 30, 2026 Drilled Completed(1) Drilled Completed(2) Area: Gross Net Gross Net Gross Net Gross Net Midland Basin 97 89 168 157 215 200 315 294 Total 97 89 168 157 215 200 315 294 (1)The average lateral length for the wells completed during the second quarter of 2026 was 11,983 feet. Operated completions during the second quarter of 2026 consisted of 41 Wolfcamp B wells, 38 Wolfcamp A wells, 31 Jo Mill wells, 31 Lower Spraberry wells, 13 Middle Spraberry wells, seven Wolfcamp D wells, five Dean wells, one Barnett well and one Upper Spraberry well. (2)The average lateral length for the wells completed during the six months ended June 30, 2026 was 11,679 feet. Operated completions during the six months ended June 30, 2026 consisted of 71 Wolfcamp B wells, 69 Wolfcamp A wells, 63 Lower Spraberry wells, 62 Jo Mill wells, 20 Middle Spraberry wells, 15 Wolfcamp D wells, 11 Dean wells, three Upper Spraberry wells and one Barnett well. 27 Table of Contents As of June 30, 2026, we operated the following wells: As of June 30, 2026 Vertical Wells Horizontal Wells Total Area: Gross Net Gross Net Gross Net Midland Basin 4,368 4,154 5,179 4,867 9,547 9,021 Delaware Basin 36 30 457 427 493 457 Total 4,404 4,184 5,636 5,294 10,040 9,478 As of June 30, 2026, we and Viper held interests in 44,314 gross (9,810 net) wells, including 1,909 gross (331 net) wells in which we have a non-operated working interest. Outlook We have increased our annual production guidance by 3% to approximately 1,000 MBOE/d based on our assessment of current market fundamentals, including global oil supply constraints that began in the first quarter of 2026 and their continuing impact on crude oil inventory levels. We expect to achieve this increase in part by continuing to convert portions of our drilled but uncompleted well balance and building upon our improved operational efficiencies. Results of Operations Comparison of the Three Months Ended June 30, 2026, and March 31, 2026 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. 28 Table of Contents The following table sets forth selected operating data for the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 Revenues (In millions): Oil sales $ 4,627 $ 3,445 Natural gas sales (276) 21 Natural gas liquid sales 435 359 Total oil, natural gas and natural gas liquid revenues $ 4,786 $ 3,825 Production Data: Oil (MBbls) 47,791 46,889 Natural gas (MMcf) 128,279 118,402 Natural gas liquids (MBbls) 23,436 21,519 Combined volumes (MBOE)(1) 92,607 88,142 Daily oil volumes (BO/d) 525,176 520,989 Daily combined volumes (BOE/d) 1,017,659 979,356 Average Prices: Oil ($ per Bbl) $ 96.82 $ 73.47 Natural gas ($ per Mcf) $ (2.15) $ 0.18 Natural gas liquids ($ per Bbl) $ 18.56 $ 16.68 Combined ($ per BOE) $ 51.68 $ 43.40 Oil, hedged ($ per Bbl)(2) $ 94.33 $ 72.53 Natural gas, hedged ($ per Mcf)(2) $ (0.34) $ 1.90 Natural gas liquids, hedged ($ per Bbl)(2) $ 18.56 $ 16.68 Average price, hedged ($ per BOE)(2) $ 52.90 $ 45.21 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl. (2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts. Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables provide information on the mix of our production for the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 Oil (MBbls) 52 % 53 % Natural gas (MMcf) 23 22 Natural gas liquids (MBbls) 25 25 100 % 100 % Three Months Ended June 30, 2026 Three Months Ended March 31, 2026 Midland Basin Delaware Basin Other Total Midland Basin Delaware Basin Other Total Production Data: Oil (MBbls) 44,209 3,565 17 47,791 42,907 3,721 261 46,889 Natural gas (MMcf) 115,656 12,242 381 128,279 104,171 12,878 1,353 118,402 Natural gas liquids (MBbls) 21,662 1,760 14 23,436 19,591 1,804 124 21,519 Total (MBOE) 85,147 7,365 95 92,607 79,860 7,671 611 88,142 29 Table of Contents 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 2026 increased by $961 million to $4.8 billion compared to the first quarter of 2026. The increase consisted of an additional $861 million attributable largely to higher average prices received for our oil production and an additional $100 million attributable to higher oil and natural gas production volumes during the second quarter of 2026. Net Sales of Purchased Oil. We enter into purchase transactions and separate sales transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments. The following table presents the net sales of purchased oil from third parties for the periods indicated: Three Months Ended (In millions) June 30, 2026 March 31, 2026 Sales of purchased oil $ 739 $ 385 Purchased oil expense 730 393 Net purchased oil sales (expense) $ 9 $ (8) Other Revenues. The following table presents other insignificant revenue for the periods indicated: Three Months Ended (In millions) June 30, 2026 March 31, 2026 Other operating income $ 37 $ 30 Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Lease operating expenses $ 552 $ 5.96 $ 547 $ 6.21 Lease operating expenses increased for the second quarter of 2026 compared to the first quarter of 2026 primarily due to higher production volumes, which was largely offset by the benefit of the Company’s cost discipline initiatives and other individually insignificant activity. Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 (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 $ 241 $ 2.60 5.0 % $ 186 $ 2.11 4.9 % Ad valorem taxes 61 0.66 1.3 82 0.93 2.1 Total production and ad valorem expense $ 302 $ 3.26 6.3 % $ 268 $ 3.04 7.0 % 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 2026 to the second quarter of 2026. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes as a percentage of oil, natural gas and natural gas liquids revenue decreased in the second quarter of 2026 due primarily to current valuations reflecting lower 2025 commodity prices. 30 Table of Contents Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expenses for the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Gathering, processing and transportation $ 113 $ 1.22 $ 120 $ 1.36 Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the periods indicated: Three Months Ended (In millions, except BOE amounts) June 30, 2026 March 31, 2026 Depletion of proved oil and natural gas properties $ 1,242 $ 1,267 Depreciation and amortization of other property and equipment 19 16 Other amortization 3 2 Asset retirement obligation accretion 8 8 Depreciation, depletion, amortization and accretion $ 1,272 $ 1,293 Oil and natural gas properties depletion rate per BOE $ 13.41 $ 14.37 Depreciation, depletion, amortization and accretion per BOE $ 13.74 $ 14.67 The decrease in depletion of proved oil and natural gas properties of $25 million for the second quarter of 2026 as compared to the first quarter of 2026 consists of an $89 million reduction attributable to the decline in depletion rate following the ceiling test impairment recorded in the first quarter of 2026, partially offset by a $64 million increase due to higher quarterly production volumes. Impairment of Oil and Natural Gas Properties. The following table shows impairment of oil and natural gas properties for the periods indicated: Three Months Ended (In millions) June 30, 2026 March 31, 2026 Impairment of oil and natural gas properties $ — $ 1,400 The non-cash ceiling test impairment charge in the first quarter of 2026 primarily resulted from a decline in SEC Prices applicable to the period. Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall as compared to the commodity prices used in the current quarter, we may have material write-downs in subsequent quarters. Currently, we do not expect to record additional impairment of our assets in the third quarter of 2026. General and Administrative Expenses. The following table shows the cash and non-cash general and administrative expenses incurred in the periods indicated: Three Months Ended June 30, 2026 March 31, 2026 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE General and administrative expenses $ 48 $ 0.52 $ 57 $ 0.65 Non-cash stock-based compensation 24 0.26 22 0.25 Total general and administrative expenses $ 72 $ 0.78 $ 79 $ 0.90 31 Table of Contents Other Operating Expenses, Net. The following table shows other insignificant operating expenses for the periods indicated: Three Months Ended (In millions) June 30, 2026 March 31, 2026 Other operating expenses, net $ 9 $ 24 Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on settlements of derivative instruments for the periods indicated: Three Months Ended (In millions) June 30, 2026 March 31, 2026 Gain (loss) on derivative instruments, net(1) $ 49 $ 117 Net cash received (paid) on settlements(1) $ 113 $ 133 (1)The three months ended June 30, 2026 includes cash received to terminate commodity contracts prior to their contractual maturity of $1 million, and the three months ended March 31, 2026 includes cash paid on interest rate swaps terminated prior to their contractual maturity of $27 million. The decrease in gain on derivative instruments for the second quarter of 2026 compared to the first quarter of 2026 primarily reflects (i) a net loss of $262 million attributable to our natural gas contracts, which was comprised of a $290 million decrease in the value of our unsettled natural gas contracts largely due to unfavorable basis differentials on our natural gas basis swap contracts, partially offset by a $28 million increase in cash received for the settlement of contracts, (ii) a net gain of $194 million attributable to our oil contracts, which was comprised of a $270 million increase in the value of our unsettled positions as market prices declined compared to our contract prices at June 30, 2026 compared to March 31, 2026, and a $76 million decrease in cash received for the settlement of contracts, and (iii) other insignificant activity. See Note 12—Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments. Other Income (Expense). The following table shows other income and expenses for the periods indicated: Three Months Ended (In millions) June 30, 2026 March 31, 2026 Interest expense, net $ (56) $ (63) Other income (expense), net $ (4) $ 7 Gain (loss) on extinguishment of debt, net $ 134 $ (1) The gain on extinguishment of debt, net for the second quarter of 2026 primarily relates to the tender offer in which we repurchased $777 million of aggregate principal value on our senior notes at an average of 81.1% of par value. See Note 8—Debt of the notes to the condensed consolidated financial statements for details regarding outstanding borrowings and retirements of senior notes. Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the periods indicated: Three Months Ended (In millions) June 30, 2026 March 31, 2026 Provision for (benefit from) income taxes $ 580 $ 32 The increase in our provision for income taxes for the second quarter of 2026 compared to the first quarter of 2026 was primarily due to the increase in pre-tax income between periods, which resulted largely from the first quarter of 2026 including a non-cash ceiling test impairment charge and an increase in our oil, natural gas and natural gas liquids revenues in the second quarter of 2026 as discussed above. See Note 11—Income Taxes of the notes to the condensed consolidated financial statements for further discussion of our income tax expense. 32 Table of Contents Comparison of the Six Months Ended June 30, 2026, and 2025 The following table sets forth selected operating data for the periods indicated: Six Months Ended June 30, 2026 2025 Revenues (In millions): Oil sales $ 8,072 $ 5,891 Natural gas sales (255) 309 Natural gas liquid sales 794 773 Total oil, natural gas and natural gas liquid revenues $ 8,611 $ 6,973 Production Data: Oil (MBbls) 94,680 87,943 Natural gas (MMcf) 246,681 210,697 Natural gas liquids (MBbls) 44,955 37,209 Combined volumes (MBOE)(1) 180,749 160,268 Daily oil volumes (BO/d) 523,094 485,873 Daily combined volumes (BOE/d) 998,613 885,459 Average Prices: Oil ($ per Bbl) $ 85.26 $ 66.99 Natural gas ($ per Mcf) $ (1.03) $ 1.47 Natural gas liquids ($ per Bbl) $ 17.66 $ 20.77 Combined ($ per BOE) $ 47.64 $ 43.51 Oil, hedged ($ per Bbl)(2) $ 83.53 $ 66.10 Natural gas, hedged ($ per Mcf)(2) $ 0.73 $ 2.35 Natural gas liquids, hedged ($ per Bbl)(2) $ 17.66 $ 20.77 Average price, hedged ($ per BOE)(2) $ 49.15 $ 44.19 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl. (2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts. Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables set forth the mix of our production data by product and basin for the periods indicated: Six Months Ended June 30, 2026 2025 Oil (MBbls) 52 % 55 % Natural gas (MMcf) 23 22 Natural gas liquids (MBbls) 25 23 100 % 100 % 33 Table of Contents Six Months Ended June 30, 2026 Six Months Ended June 30, 2025 Midland Basin Delaware Basin Other Total Midland Basin Delaware Basin Other Total Production Data: Oil (MBbls) 87,116 7,286 278 94,680 80,980 6,877 86 87,943 Natural gas (MMcf) 219,827 25,120 1,734 246,681 191,322 18,746 629 210,697 Natural gas liquids (MBbls) 41,253 3,564 138 44,955 34,615 2,545 49 37,209 Total (MBOE) 165,007 15,037 705 180,749 147,482 12,546 240 160,268 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, 2026, increased by $1.6 billion, or 23%, to $8.6 billion from the same period in 2025. This net increase consisted of an additional $973 million from higher average prices received for our oil production, offset partially by lower natural gas and natural gas liquids prices received in 2026 and an additional $665 million from the 13% growth in our combined production volumes. Approximately 33% of the increase in our combined production volumes was attributable to Viper’s Sitio Acquisition and 16% was 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 enter into purchase transactions and separate sales transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments. The following table presents the net sales of purchased oil from third parties for the periods indicated: Six Months Ended June 30, (In millions) 2026 2025 Sales of purchased oil $ 1,124 $ 709 Purchased oil expense 1,123 713 Net purchased oil sales (expense) $ 1 $ (4) Other Revenues. The following table shows other revenues for the periods indicated: Six Months Ended June 30, (In millions) 2026 2025 Other operating income $ 67 $ 44 Other operating income increased for the six months ended June 30, 2026, compared to the same period in 2025, primarily due to a $13 million increase in lease bonus income recorded by Viper following its Sitio Acquisition and the 2025 Drop Down, as well as other individually insignificant activity. Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated: Six Months Ended June 30, 2026 2025 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Lease operating expenses $ 1,099 $ 6.08 $ 848 $ 5.29 Lease operating expenses increased for the six months ended June 30, 2026, compared to the same period in 2025, primarily due to (i) a $54 million increase in water disposal costs following the divestiture of the Company’s Environmental Disposal Systems, LLC subsidiary in the fourth quarter of 2025, (ii) recording a $43 million reduction in estimated prior period water related costs during the six months ended June 30, 2025, (iii) a $36 million increase to operate wells acquired in the Double Eagle Acquisition, (iv) a $35 million increase in workover and maintenance costs and (v) a $34 million increase attributable to higher production volumes during the six months ended June 30, 2026, (vi) a downward adjustment to initial cost estimates related to producing properties acquired in connection with the Endeavor Acquisition during the six months ended June 30, 2025, and (vii) other individually insignificant activity. 34 Table of Contents Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the periods indicated: Six Months Ended June 30, 2026 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 $ 427 $ 2.36 4.9 % $ 327 $ 2.04 4.7 % Ad valorem taxes 143 0.79 1.7 115 0.72 1.6 Total production and ad valorem expense $ 570 $ 3.15 6.6 % $ 442 $ 2.76 6.3 % 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 remained consistent in the first half of 2026 compared to the first half 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 per BOE and as a percentage of revenue from sales of oil, natural gas and natural gas liquids for the six months ended June 30, 2026, compared to the same period in 2025. Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expenses for the periods indicated: Six Months Ended June 30, 2026 2025 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Gathering, processing and transportation $ 233 $ 1.29 $ 256 $ 1.60 The decrease in gathering, processing and transportation expense for the six months ended June 30, 2026, compared to the same period in 2025 primarily relates to higher utilization of arrangements that require net presentation within related revenues in the second quarter of 2026, partially offset by an increase due to increased production volumes for the six months ended June 30, 2026. Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the periods indicated: Six Months Ended June 30, (In millions, except BOE amounts) 2026 2025 Depletion of proved oil and natural gas properties $ 2,509 $ 2,295 Depreciation and amortization of other property and equipment 35 46 Other amortization 5 4 Asset retirement obligation accretion 16 18 Depreciation, depletion, amortization and accretion $ 2,565 $ 2,363 Oil and natural gas properties depletion rate per BOE $ 13.88 $ 14.32 Depreciation, depletion, amortization and accretion per BOE $ 14.19 $ 14.74 The increase in depletion of proved oil and natural gas properties of $214 million for the six months ended June 30, 2026, compared to the same period in 2025 consists of $293 million from growth in production volumes, which was partially offset by a $79 million reduction attributable to a decrease in the depletion rate. The depletion rate declined due to a reduction in the depletable asset base, which was caused by the ceiling test impairment recorded in the fourth quarter of 2025 and the first quarter of 2026 as discussed below. This reduction was partially offset by the addition of higher value leasehold costs and proved reserves to the depletable base from the Double Eagle Acquisition and, to a lesser extent, Viper’s Sitio Acquisition. 35 Table of Contents Impairment of Oil and Natural Gas Properties. The following table shows impairment of oil and natural gas properties for the periods indicated: Six Months Ended June 30, (In millions) 2026 2025 Impairment of oil and natural gas properties $ 1,400 $ — The non-cash ceiling test impairment charge of $1.4 billion for the six months ended June 30, 2026 primarily resulted from the decline in SEC Prices during the preceding twelve months. General and Administrative Expenses. The following table shows the cash and non-cash general and administrative expenses incurred in the periods indicated: Six Months Ended June 30, 2026 2025 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE General and administrative expenses $ 105 $ 0.58 $ 101 $ 0.63 Non-cash stock-based compensation 46 0.25 39 0.24 Total general and administrative expenses $ 151 $ 0.83 $ 140 $ 0.87 Other Operating Expenses, Net. The following table shows the other operating expenses for the periods indicated: Six Months Ended June 30, (In millions) 2026 2025 Other operating expenses, net $ 33 $ 152 The decrease in other operating expenses for the six months ended June 30, 2026, compared to the same period in 2025 primarily resulted from (i) a $72 million reduction in merger and transaction costs due to the 2025 period, including costs incurred for the Endeavor Acquisition, the 2025 Drop Down and other individually insignificant transactions, and (ii) a $45 million decrease in midstream service expense following the divestiture of the Company’s Environmental Disposal Systems, LLC subsidiary in the fourth quarter of 2025. Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on settlements of derivative instruments for the periods indicated: Six Months Ended June 30, (In millions) 2026 2025 Gain (loss) on derivative instruments, net(1) $ 166 $ 29 Net cash received (paid) on settlements(1) $ 246 $ 48 (1)The six months ended June 30, 2026, includes cash paid on interest rate swaps terminated prior to their contractual maturity of $27 million and cash received for the early termination of commodity contracts of $1 million. The increase in gain on derivative instruments for the six months ended June 30, 2026, compared to the same period in 2025 primarily reflects (i) a $278 million gain attributable to our natural gas contracts, which was comprised of a $249 million increase in cash received upon settlement of contracts and a $29 million increase in the value of our unsettled natural gas costless collars and basis swaps, and (ii) other insignificant changes due to the termination of our interest rate swaps. These gains were partially offset by an additional loss of $124 million attributable to our oil contracts, which was comprised of (i) a $103 million decrease in the value of our unsettled contracts due primarily to basis puts and puts added between periods being in a liability position, (ii) an $85 million decrease in cash received for the settlement of contracts and (iii) a $64 million increase in the value of our unsettled roll swaps and basis swaps. See Note 12—Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments. 36 Table of Contents Other Income (Expense). The following table shows other income and expenses for the periods indicated: Six Months Ended June 30, (In millions) 2026 2025 Interest expense, net $ (119) $ (96) Other income (expense), net $ 3 $ 37 Gain (loss) on extinguishment of debt, net $ 133 $ 55 Interest expense, net increased by $23 million for the six months ended June 30, 2026, compared to the same period in 2025. This increase primarily consisted of (i) a $32 million decrease in capitalized interest costs, which increased interest expense, (ii) a net increase of $18 million related to the issuance of Viper’s 4.900% Senior Notes due 2030 and 5.700% Senior Notes due 2035 and the redemption of its 5.375% Senior Notes due 2027 and 7.375% Senior Notes due 2031 in the third quarter of 2025, and (iii) a $15 million increase attributable to the 2035 Notes issued in April 2025. These increases were partially offset by a $50 million reduction in interest expense due to retirements of the Company’s debt during 2026 and 2025 and other individually insignificant activity. See Note 8—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, 2026, decreased compared to the same period in 2025, primarily due to receiving a $42 million distribution from an equity method investee during the six months ended June 30, 2025, partially offset by a $10 million increase in income from equity method investees and other individually insignificant items. Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the periods indicated: Six Months Ended June 30, (In millions) 2026 2025 Provision for (benefit from) income taxes $ 612 $ 607 See Note 11—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 the Revolving Credit Facility and term loan agreements, 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, 2026, we had approximately $3.4 billion of liquidity consisting of $385 million in standalone cash and cash equivalents and $3.0 billion available under our credit facility. At June 30, 2026, we had approximately $1.5 billion of senior notes maturing in the next 12 months. Future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the volatility of commodity prices. In order to mitigate volatility in oil and natural gas prices, we enter into derivative contracts as discussed further in Note 12—Derivatives of the notes to the condensed consolidated financial statements of this report. 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. 37 Table of Contents Cash Flow Our cash flows for the six months ended June 30, 2026, and 2025 are presented below: Six Months Ended June 30, 2026 2025 (In millions) Net cash provided by (used in) operating activities $ 5,417 $ 4,032 Net cash provided by (used in) investing activities (2,053) (5,632) Net cash provided by (used in) financing activities (3,006) 1,657 Net increase (decrease) in cash $ 358 $ 57 Operating Activities The increase in operating cash flows for the six months ended June 30, 2026, compared to the same period in 2025 primarily resulted from (i) $1.7 billion in additional revenues, excluding sales of purchased oil, (ii) an increase of $198 million in cash received on settlements of derivatives, and (iii) a decrease of $98 million in cash paid for taxes. These were partially offset by (i) changes in working capital accounts, excluding taxes payable, of $295 million due primarily to higher prices received for oil sales accrued at June 30, 2026 compared to June 30, 2025 and the timing of when payments are made or received, and (ii) higher cash operating expenses, excluding purchased oil expense, of approximately $241 million. 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, 2026, was for drilling and completion costs incurred in conjunction with our development program as well as the acquisition of properties and equipment. These cash expenditures were partially offset by the proceeds from the Viper Non-Permian Divestiture. See Note 4—Acquisitions and Divestitures for further discussion of the Viper Non-Permian Divestiture. The majority of our net cash used in investing activities during the six months ended June 30, 2025, was for drilling and completion costs incurred in conjunction with our development program as well as the acquisition of properties and equipment for the Double Eagle Acquisition. 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, 2026 2025 (In millions) Operated drilling and completion additions to oil and natural gas properties(1) $ (1,626) $ (1,571) Non-operated additions to oil and natural gas properties and other (303) (235) Total $ (1,929) $ (1,806) (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, 2026. Financing Activities During the six months ended June 30, 2026, net cash used in financing activities was primarily attributable to (i) $1.1 billion for the repayment of our 2025 Term Loan and the Viper 2025 Term Loan, (ii) $917 million of repurchases as part of our and Viper’s share repurchase programs, (iii) $697 million in repurchases of senior notes, (iv) $609 million of dividends paid to stockholders, including dividend equivalent rights, (v) $279 million in dividends paid to non-controlling interest, (vi) $10 million in repayments on our credit facilities, net of borrowings, and (vii) various other individually insignificant costs. These cash outflows were partially offset by $589 million in proceeds from the Secondary Offering. 38 Table of Contents 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 5.550% senior notes due in 2035, (iii) $1.2 billion in proceeds from Viper’s public offering of Class A common stock, and (iv) $659 million in borrowings under 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 in borrowings on a previously outstanding term loan, (iii) $584 million of dividends paid to our stockholders, including dividend equivalent rights, (iv) $244 million in repurchases of senior notes, (v) $177 million in dividends paid to non-controlling interest, and (vi) various other individually insignificant costs. Capital Resources Our working capital requirements are primarily supported by our cash and cash equivalents and available borrowings under the Revolving Credit Facility. We may draw on the 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 funding requirements. Revolving Credit Facilities Diamondback’s Revolving Credit Facility As of June 30, 2026, our Revolving Credit Facility, which matures on June 12, 2031, had a maximum credit amount of $3.0 billion, which was fully available for future borrowings. Viper’s Revolving Credit Facility The Viper Revolving Credit Facility, which matures on June 12, 2031, provides for a commitment amount of $2.0 billion. As of June 30, 2026, the Viper Revolving Credit Facility had $95 million in outstanding borrowings and approximately $1.9 billion available for future borrowings. For additional discussion of our revolving credit facilities as of June 30, 2026, see Note 8—Debt of the notes to the condensed consolidated financial statements. Capital Requirements 2026 Capital Spending Plan In support of our long-term strategy, we expect to continue adjusting our development activity in response to market conditions, including converting a portion of our drilled but uncompleted well inventory into producing wells. We expect our inventory of development locations to enhance operational flexibility by providing the ability to adjust capital allocation, activity levels and development timing as market conditions evolve. As previously announced, in the second quarter of 2026, our board of directors approved increasing our 2026 capital budget guidance by 4% to approximately $3.90 billion, which includes $3.31 billion for operated horizontal drilling and completions. 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 17 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. Debt Instruments As of June 30, 2026, our debt, including the debt of Viper, consisted of approximately $12.7 billion in aggregate outstanding principal amount of senior notes and $95 million in aggregate outstanding borrowings under revolving credit facilities. 39 Table of Contents Other Contractual Obligations and Commitments We entered into a fixed price contract for the purchase of electrical power from 2028 through 2034 during the three and six months ended June 30, 2026. As a result, we expect to incur additional future electrical power costs of approximately $519 million in the aggregate through 2034. See Note 15—Commitments and Contingencies of the notes to the condensed consolidated financial statements for further information regarding this commitment. Return of Capital Commitment Beginning in the second quarter of 2026, our board of directors approved the removal of our minimum 50% return of capital quarterly commitment to allow the Company more discretion in the allocation of Free Cash Flow. Further, on July 30, 2026, our board of directors declared a base cash dividend for the second quarter of 2026 of $1.10 per share of common stock. On July 30, 2026, our board of directors approved an increase in our common stock repurchase program, from $8.0 billion to $16.0 billion, excluding the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the IRA. Since the inception of the stock repurchase program through July 31, 2026, we have repurchased an aggregate of 43.0 million shares of our common stock for a total cost of $6.1 billion, which includes $814 million for the repurchase of 5.0 million shares from SGF, excluding excise tax, leaving approximately $9.9 billion for future repurchases under such stock repurchase program. Subject to regulatory restrictions and other factors discussed elsewhere in this report, we intend to continue to purchase shares under this repurchase program opportunistically with available funds primarily from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs; however, the stock repurchase program is at the discretion of our board of directors and can be amended, terminated or suspended at any time. Repurchases may be executed in privately negotiated or open-market transactions, consistent with Rule 10b-18 under the Securities Exchange Act of 1934 and other applicable requirements. All shares repurchased will be retired. See Note 9—Stockholders’ Equity and Earnings (Loss) Per Share of the notes to the condensed consolidated financial statements for further discussion of our stock repurchase program. Guarantor Financial Information Diamondback E&P is the sole guarantor under the indentures governing the outstanding Guaranteed Senior Notes. Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the indentures governing the Guaranteed Senior Notes, such as, with certain exceptions, (i) in the event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (ii) in the event Diamondback E&P ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (iii) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture. Diamondback E&P’s guarantees of the Guaranteed Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under the 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. 40 Table of Contents 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, 2026 December 31, 2025 Summarized Balance Sheets: (In millions) Assets: Current assets $ 1,111 $ 844 Property and equipment, net $ 18,674 $ 19,670 Other noncurrent assets $ 190 $ 142 Liabilities: Current liabilities $ 4,615 $ 3,304 Intercompany accounts payable, non-guarantor subsidiary $ 8,524 $ 6,970 Long-term debt $ 9,388 $ 11,540 Other noncurrent liabilities $ 1,913 $ 2,186 Six Months Ended June 30, 2026 Summarized Statement of Operations: (In millions) Revenues $ 4,052 Income (loss) from operations(1) $ (119) Net income (loss) $ (402) (1)During the six months ended June 30, 2026, the Company recorded a non-cash impairment that is reflected in the summarized results of the guarantor group. This impairment is not indicative of cash flows available for debt service. 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, 2025. 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.