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1 Q2 2026 Investor Presentation August 2026
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2 Forward-Looking Statements & Non-GAAP Financial Measures Forward-Looking Statements This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions. All statements, other than statements of historical fact, that Diamondback Energy, Inc. (“Diamondback,” the “Company” or “we”) makes, including statements regarding future performance; business strategy; future operations (including drilling plans and capital plans); estimates and projections of revenues, losses, costs, expenses, returns, cash flow, and financial position; reserve estimates and its ability to replace or increase reserves; anticipated benefits or other effects of strategic transactions (including the Double Eagle acquisition, Sitio acquisition completed by Viper, Riverbend acquisition completed by Viper and other acquisitions, divestitures or reorganizations), and plans and objectives of management (including plans for future cash flow from operations and for executing on environmental strategies and targets) are forward-looking statements. When used in this presentation, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to the Company are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Although the Company believes that the expectations and assumptions reflected in its forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control. Accordingly, forward-looking statements are not guarantees of future performance and the Company’s actual outcomes could differ materially from what the Company has expressed in its forward-looking statements. Factors that could cause the outcomes to differ materially include (but are not limited to) the following: geopolitics and market conditions, including changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities; changes in U.S. energy, environmental, monetary and trade policies, including with respect to tariffs or other trade barriers and any resulting trade tensions; actions taken by the members of OPEC and its non-OPEC allies (OPEC+) affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments; changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates, inflation rates, and instability in the financial markets; regional supply and demand factors, including delays, curtailment delays or interruptions of production, or governmental orders, rules or regulations that impose production limits; federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations; physical and transition risks relating to climate change, changing political and social perspectives on climate change and other environmental, social and governance factors, and risks from our publicly disclosed targets related to sustainability and emissions reduction initiatives; challenges in developing our existing leasehold acreage and finding, developing or acquiring additional reserves; restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water disposal well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin; significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges; conditions in the capital, financial and credit markets, including the availability and pricing of capital for acquisitions, exploration and development operations; challenges with employee retention and an increasingly competitive labor market; changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services; changes in safety, health, environmental, tax and other regulations or requirements (including those addressing air emissions, water management, or the impact of global climate change); security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business; lack of, or disruption in, access to adequate and reliable electrical power, internet and telecommunication infrastructure, information and computer systems, transportation, processing, storage and other facilities for our oil, natural gas and natural gas liquids; failures or delays in achieving expected reserve or production levels from existing and future oil and natural gas developments, including due to operating hazards, drilling risks, or the inherent uncertainties in predicting reserve and reservoir performance; inability to keep pace with technological developments in our industry; failure to meet our obligations under our oil purchase contracts; loss of one or more customers or their inability to meet their obligations; geographical concentration of our primary operations; risks from our return of capital commitment, and uncertainties over our future dividends and share repurchases; difficulty in obtaining necessary approvals and permits; severe weather conditions and natural disasters; changes in the financial strength of counterparties to our credit facilities and hedging contracts; our substantial indebtedness and restrictions to our operating and financial flexibility; changes in our credit rating; failure to identify, complete and successfully integrate acquisitions, including the Double Eagle Acquisition, Viper’s Riverbend acquisition, and Viper's Sitio Acquisition; the Endeavor stockholders' ability to significantly influence our business and potential conflicts of interest; and those other risks described in Part I, Item 1A of Diamondback’s Annual Report on Form 10-K, filed with the SEC on February 25, 2026, and those risks disclosed in its subsequent filings on Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the SEC’s website at http://www.sec.gov and Diamondback’s website at www.diamondbackenergy.com/investors. In light of these factors, the events anticipated by the Company’s forward-looking statements may not occur at the time anticipated or at all. Moreover, the Company operates in a very competitive and rapidly changing environment and new risks emerge from time to time. The Company cannot predict all risks, nor can it assess the impact of all factors on its business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those anticipated by any forward-looking statements it may make. Accordingly, you should not place undue reliance on any forward- looking statements made in this presentation. All forward-looking statements speak only as of the date of this presentation or, if earlier, as of the date they were made. The Company does not intend to, and disclaims any obligation to, update or revise any forward-looking statements unless required by applicable law. The presentation also contains the Company’s updated capital expenditure and production guidance, and certain forward-looking information, with respect to 2026. The actual levels of production, capital expenditures, expenses and other estimates may be higher or lower than these estimates due to, among other things, uncertainty in drilling schedules, changes in market demand, commodity prices and unanticipated delays in production. These estimates are based on numerous assumptions, including assumptions related to number of wells drilled, average spud to release times, rig count, and production rates for wells placed on production. All or any of these assumptions may not prove to be accurate, which could result in actual results differing materially from estimates. If any of the rigs currently being utilized or intended to be utilized becomes unavailable for any reason, and the Company is not able to secure a replacement on a timely basis, we may not be able to drill, complete and place on production the expected number of wells. Similarly, average spud to release times may not be maintained in 2026. No assurance can be made that new wells will produce in line with historic performance, or that existing wells will continue to produce in line with expectations. The Company’s ability to fund its 2026 and future capital budgets is subject to numerous risks and uncertainties, including volatility in commodity prices and the potential for unanticipated increases in costs associated with drilling, production and transportation. In addition, its production estimate assumes there will not be any new federal, state or local regulation of portions of the energy industry in which the Company operates, or an interpretation of existing regulation, that will be materially adverse to its business. For additional discussion of the factors that may cause it not to achieve its production estimates, see the Company’s filings with the SEC, including its forms 10-K, 10-Q and 8-K and any amendments thereto. The Company does not undertake any obligation to release publicly the results of any future revisions it may make to this prospective data or to update this prospective data to reflect events or circumstances after the date of this presentation. Therefore, you are cautioned not to place undue reliance on this information. Non-GAAP Financial Measures Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Consolidated Adjusted EBITDA as net income (loss) attributable to Diamondback Energy, Inc., plus net income (loss) attributable to non-controlling interest ("net income (loss)") before non-cash (gain) loss on derivative instruments, net, interest expense, net, depreciation, depletion, amortization and accretion, depreciation and interest expense related to equity method investments, (gain) loss on extinguishment of debt, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, other non-cash transactions and provision for (benefit from) income taxes, if any. Consolidated Adjusted EBITDA is not a measure of net income as determined by United States generally accepted accounting principles ("GAAP"). Management believes Consolidated Adjusted EBITDA is useful because the measure allows it to evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income (loss) to determine Consolidated Adjusted EBITDA because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Further, the Company excludes the effects of significant transactions that may affect earnings but are unpredictable in nature, timing and amount, although they may recur in different reporting periods. Consolidated Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of the Company’s operating performance. Certain items excluded from Consolidated Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets. The Company’s computation of Consolidated Adjusted EBITDA may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts. For a reconciliation of Consolidated Adjusted EBITDA to net income (loss), and other non-GAAP financial measures, please refer to our earnings release furnished to, and other filings we make with, the SEC and the appendix attached to this presentation under “Non-GAAP Definitions and Reconciliations.” Operating cash flow before working capital changes, which is a non-GAAP financial measure, represents net cash provided by operating activities as determined under GAAP without regard to changes in working capital. The Company believes operating cash flow before working capital changes is a useful measure of an oil and gas company’s ability to generate cash used to fund exploration, development and acquisition activities and service debt or pay dividends. The Company also uses this measure because changes in working capital relate to the timing of cash receipts and disbursements that the Company may not control and may not relate to the period in which the operating activities occurred. Free Cash Flow, which is a non-GAAP financial measure, is cash flow from operating activities before changes in working capital in excess of cash capital expenditures. Adjusted Free Cash Flow, which is a non-GAAP financial measure, is Free Cash Flow before the tax impact from divestitures, merger and transaction expenses, costs of early termination of derivatives and settlements of any treasury locks (if any). The Company believes that Free Cash Flow and Adjusted Free Cash Flow are useful to investors as they provide a measure to compare both cash flow from operating activities and additions to oil and natural gas properties across periods on a consistent basis, adjusted, as applicable, for non-recurring impacts from divestitures, merger and transaction expenses, the early termination of derivative contracts and settlements of treasury locks. These measures should not be considered as an alternative to, or more meaningful than, net cash provided by operating activities as an indicator of liquidity. The Company's computation of operating cash flow before working capital changes, Free Cash Flow and Adjusted Free Cash Flow may not be comparable to other similarly titled measures of other companies. The Company uses Free Cash Flow to reduce debt and increase the return of capital to stockholders as determined by the Board of Directors. For reconciliations of net cash provided by operating activities to operating cash flow before working capital changes and to Free Cash Flow and to Adjusted Free Cash Flow, please refer to our earnings release furnished to, and other filings we make with, the SEC and the appendix attached to this presentation under “Non-GAAP Definitions and Reconciliations.” Net debt, which is a non-GAAP measure, is total debt (excluding debt issuance costs, discounts, premiums and unamortized basis adjustments) less cash and cash equivalents and restricted cash that has been irrevocably deposited for the redemption of principal amounts of outstanding senior notes. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. The Company believes this metric is useful to analysts and investors in determining the Company's leverage position because the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. For a reconciliation of net debt to total debt, please refer to our earnings release furnished to, and other filings we make with, the SEC and the appendix attached to this presentation under “Non-GAAP Definitions and Reconciliations.” Cash Return on Capital Invested, which is a non-GAAP measure, is calculated as debt-adjusted cash flow from operations before working capital changes divided by capital invested. Capital invested is calculated as total assets plus accumulated DD&A minus cash and cash equivalents minus non-interest- bearing current liabilities. Furthermore, this presentation includes or references certain forward-looking, non-GAAP financial measures, such as estimated free cash flow for 2026, pre-tax income attributable to the Company and certain related estimates regarding future performance, results and financial position. Because the Company provides these measures on a forward-looking basis, it cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments, future changes in working capital, future commodity prices, pace of and costs of developing, producing and operating the Company’s interest in oil and natural gas properties, future changes in interest rates and various other business factors impacting the Company’s financial results. Accordingly, the Company is unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. The unavailable information could have a significant impact on our ultimate results. However, the Company believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing the Company’s forecasted financial performance to the forecasted financial performance of other companies in the industry. Oil and Gas Reserves The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. The Company discloses only estimated proved reserves in its filings with the SEC. The Company’s estimated proved reserves (including those of its consolidated subsidiaries) as of December 31, 2025, referenced in this presentation were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., an independent petroleum engineering firm, and comply with definitions promulgated by the SEC. Additional information on the Company’s estimated proved reserves is contained in the Company’s filings with the SEC. This presentation also contains the Company’s internal estimates of its potential drilling locations, which may prove to be incorrect in a number of material ways. Actual number of locations that may be drilled may differ substantially.
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3 Development Strategy Maximizes Resource and Returns High-Quality, Durable Midland Basin Inventory Investment Grade Balance Sheet Stable Cash Flow Creation Through the Cycles Best-In-Class Execution Disciplined Capital Allocator with Differentiated Returns
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4 The Premier Permian Pure-Play Operator Stable Cash Flow Through the Cycles Expect to generate ~$7.8 billion of Free Cash Flow (“FCF”) in 2026 at current commodity prices(1)(2) Current production levels and base dividend protected down to $36 / Bbl(3) Best-In-Class Execution Industry leading cost structure with ~$550 / ft. Midland Basin drilling, completion and equipment well costs Disciplined Capital Allocator Declared a quarterly base cash dividend of $1.10 per share, up 10% year over year ($4.40 per share annually) Share repurchase authorization doubled to $16 billion with ~$9.9 billion remaining Development Strategy Maximizes Resource and Returns Multi-zone co-development execution drives leading well productivity Development strategy combined with the lowest well costs in the basin produces the highest returns per well and drilling spacing unit High-Quality, Durable Inventory ~902,000 net acres with nearly 9,000 locations economic at $50 / Bbl Investment Grade Balance Sheet Investment grade credit ratings: Baa2 (Moody’s), BBB (S&P) and BBB+ (Fitch) Net debt of ~$12.3 billion; down ~16% from year-end 2025(4) Source: Company data, filings and estimates. Financial data as of 6/30/2026. Market data as of 7/31/2026. (1) Free Cash Flow defined as cash flow from operating activities before changes in working capital in excess of cash capital expenditures. (2) Based on strip pricing as of 7/31/2026. We are unable to present a quantitative reconciliation because we cannot reliably predict certain necessary components of operating cash flow, such as changes in working capital. See “Forward-Looking Statements and Non-GAAP Financial Measures” on slide 2 for additional cautionary information. (3) Breakeven WTI oil price calculated as the per barrel price for oil needed to generate cash flow equivalent to the amount of c apital required to maintain 2026 oil production levels and pay the $4.40 / share annual base dividend. Assumes $3.00/Mcf Henry Hub gas prices and $20/ Bbl NGL prices; excludes the impact of current commodity hedges . (4) Consolidated net debt, a non-GAAP measure, is defined as total debt (excluding debt issuance costs, discounts, premiums and unamortized basis adjustments) less cash and cash equivalents and restricted cash that has been irrevocably deposited for the redemption of principal amounts of outstanding senior notes. (5) 2Q26 Adjusted Free Cash Flow excludes $1 million of merger and transaction expenses. FANG NASDAQ $56.8B Mkt Cap $75.2B Enterprise Value $12.3B Net Debt(4) 280 MM Shares 2.2% Dividend Yield 525 (1,018) 2Q26 Mbo/d (Mboe/d) 1,868 Bo/d per MM Shares $3.9B Diamondback Acreage Map and Recent HighlightsDiamondback Value Creation ~902,000 net acres • 8,854 locations economic at $50/Bbl • Midland Basin Focus 2Q26 Cons. Adj. EBITDA $2.3B $8.29 / share 2Q26 Adj. FCF(5)
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5 $6,200+ $6,900+ $7,600+ $8,300+ ~8% ~9% ~10% ~11%~11% ~12% ~13% ~15% $60 / Bbl $70 / Bbl $80 / Bbl $90 / Bbl FCF Yield (%)(4) FCF ($MM) Base Dividend Excess FCF FCF Yield (EV) FCF Yield (Market Cap) ~$625 ~$600 ~$560 ~$550 ~$530 $0 $50 $10 0 $15 0 $20 0 $25 0 $30 0 $35 0 $40 0 $45 0 $50 0 $55 0 $60 0 $65 0 $70 0 $75 0 $80 0 2023 2024 2025 Current 2026 2026 excluding Barnett Adj. Free Cash Flow(2) $MM Oil Production / Share(1) Bo/d per MM Shares Midland Basin D,C&E Well Costs $ / Ft. Average Lateral Length Ft. Consolidated 2026E Free Cash Flow at Various WTI Prices(3) Oil Production Net Mbo/d Overview of the 2026 Plan 2026 Plan and Implied Improvement vs 2025 Midland Basin D,C&E Well Costs ($ / Ft.) -8% vs. 2024 -12% vs. 2023 -2% vs. 2025 2026 Midland Basin Well Costs $22+ $24+ $27+ $29+ Free Cash Flow per Share(1) Source: Company data, filings and estimates. (1) Assumes FANG’s 2026 estimated weighted average share count of approximately 281 million shares. (2) Current 2026 plan estimated adjusted free cash flow based on strip pricing as of 7/31/2026, versus original 2026 plan forecasted free cash flow based on strip pricing as of 2/20/2026. We are unable to present a quantitative reconciliation because we cannot reliably predict certain necessary components of operating cash flow, such as changes in working capital. See “Forward-Looking Statements and Non-GAAP Financial Measures” on slide 2 for additional cautionary information. (3) Pricing realizations for each scenario assume >98% WTI, $18/Bbl NGL, and $3.00/Mcf Henry Hub net of applicable differentials as of 7/31/2026. Activity, CAPEX, production, and operating/well costs are held constant in each scenario per our 2026 guidance on slide 13 and reflect existing hedges and a $4.40 / share annual base dividend. See footnote 1 on slide 4 for FCF definition, and “Forward-Looking Statements and Non-GAAP Financial Measures” on slide 2 for additional cautionary information. (4) Free cash flow yield calculated as free cash flow divided by FANG’s enterprise value (“EV”) and FANG’s market capitalization (“Market Cap”) as of 7/31/2026, respectively. $555 – $605 Original 2025 Guidance 2025A Current 2026 Plan Original 2026 Plan Base Dividend $ / Share 1,720 1,789 ~1,858 $560 $550 $550 12,138’ 12,900’ 12,900’ $5,892 ~$4,700 ~$7,800 $4.05 $4.20 $4.40 497.2 505 522+ Δ YoY +5% +8% -2% +6% +32% +9%
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6 $6,124 repurchased $431 $1,097 $838 $959 $2,010 $789 $9,876 remaining 4.1 12.8 19.1 24.6 38.4 43.0 0.0 0 5.0 0 10. 00 15. 00 20. 00 25. 00 30. 00 35. 00 40. 00 45. 00 $0 $2, 000 $4, 000 $6, 000 $8, 000 $10 ,000 $12 ,000 $14 ,000 $16 ,000 2H 2021 2022 2023 2024 2025 YTD 2026 Cumulative Stock Repurchases ($MM) Cumulative Shares Repurchased (MM) $0.50 $0.94 $1.53 $1.95 $3.00 $3.38 $3.70 $4.05 $4.40 2018 2019 2020 2021 2022 2023 2024 2025 Current Run-Rate • $4.40/share base dividend protected down to $36 / Bbl WTI (5) • ~7% avg quarterly CAGR since inaugural base dividend • +8.8x base dividend growth 880% 100% 295% 159% 551% 126% 400% 34%0% 100% 200% 300% 400% 500% 600% 700% 800% 900%% of Q1 2018 Dividend Return of Capital Since the Inaugural Base Dividend Declared Base Dividends Since 2018 ($ / Share) Source: Company data, filings and estimates. (1) Paid Return of Capital through 6/30/2026. (2) Year-to-date ROC includes declared 2Q 2026 dividends payable in 3Q 2026 as well as stock repurchases to date in the third quarter. (3) Peer data through 7/31/2026. Peers include EOG, OVV, DVN, COP, CVX, XOM, APA and OXY. (4) Shares repurchased through 7/31/2026. (5) Breakeven WTI oil price calculated as the per barrel price for oil needed to generate cash flow equivalent to the amount of capital required to maintain 2026 oil production levels and pay the $4.40 / share annual base dividend. Assumes $3.00/Mcf Henry Hub gas prices and $20/Bbl NGL prices; excludes the impact of current commodity hedges. Diamondback allocates capital to maximize long-term shareholder value – a flexible strategy built to enhance returns through the commodity cycle Normalized Dividend Growth versus Peers (% of Q1 2018 Base DPS)(3) $16.0 Billion Authorized Stock Repurchase Program(4) $12,394 $1,824 $2,670 $2,282 $2,539 $3,167 $1,293 $13,776 $14,186 $0 $3 $6 $9 $12 $15 $18 $21 $24 $27 $30 $33 $36 0 100 0 200 0 300 0 400 0 500 0 600 0 700 0 800 0 900 0 100 00 110 00 120 00 130 00 140 00 150 00 18-21 2022 2023 2024 2025 1H 2026 Total ROC YTD FANG's 12/31/2017 Market Cap Base Dividends ($MM) Variable Dividend ($MM) Stock Repurchases ($MM) DPS - Paid $35.70 $36.80 Diamondback’s Prudent History of Return of Capital 43.0MM shares repurchased to date ~$9.9 billion remaining (~62% of authorization) (2)(1)
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7 8.0% 13.2% 10.1% 12.1% 7.8% 12.9% 18.1% 14.0% 10.6% 10.4% 0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20% 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 CROCI vs. WACC (%) Year CROCI - WACC Spread CROCI WACC 18.7 8.8 4.1 4.6 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Per-Share Compounding - (Log Scale - Base 2) FCF/Share Dividend/Share Oil/Share Reserves/Share Capital Discipline and Return on Capital Through the Cycles Cash Return on Capital Invested (CROCI)(1) vs. Weighted Average Cost of Capital (WACC) Accretive Per-Share Compounding 10-YR Avg. Spread +310 bps CROCI over WACC, 2016 – 2025 Positive spread for past decade Growth over the last decade has been accretive • A share held since 2016 would claim 4.1x the oil production and 4.6x the reserves per share vs. 2016 • 18.7x the free cash flow per share since 2020 • 8.8x the dividend per share since initiation in 2018 (2) WTI Price Throughout the past decade, Diamondback has consistently generated cash returns above its cost of capital while simultaneously compounding per share metrics WTI Price Source: Company data, Bloomberg data, filings and estimates. (1) Cash Return on Capital Invested calculated as debt -adjusted cash flow from operations before working capital changes divided by capital invested. Capital invested calculated as total assets plus accumulated DD&A minus cash and cash equivalents minus non-interest-bearing current liabilities. (2) Growth calculated with new annual run-rate base dividend of $4.40 per share.
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8 33% 34% 38% 42% 44% 44% 44% 45% 49% 50% 1.5x 1.1x 1.0x 1.7x 1.4x 1.7x 1.3x 1.0x 2.0x 1.9x 0x 1x 2x 3x 4x 5x 6x 7x 8x 0% 10% 20% 30% 40% 50% 60% 70% 80% FANG Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Reinvestment Rate Total Debt / Free Cash Flow 48.9 44.2 37.6 36.6 35.4 35.3 33.7 33.5 29.8 29.2 0.0 10. 0 20. 0 30. 0 40. 0 50. 0 FANG Peer 3 Peer 6 Peer 5 Peer 4 Peer 1 Peer 9 Peer 8 Peer 7 Peer 2 Source: Company data, filings and estimates. Peers include CVX, XOM, OXY, APA, DVN, PR, EOG, OVV, and COP. (1) Diamondback estimates based on announced guidance and expected total debt at YE2026. Bloomberg data and estimates used for pe ers as of 7/31/2026. (2) Reinvestment rate defined as cash CAPEX divided by operating cash flow before working capital changes. (3) 2026E oil production per $MM of CAPEX based on Diamondback’s 2026 guidance and reported 2026 guidance for peers as of 7 /31/2026. (4) CAPEX estimates include the addition of exploration expense estimates from Bloomberg for successful efforts accounting companies. 2026E Reinvestment Rate and Total Debt / Free Cash Flow vs. Peers(1)(2) 2026E Oil Production per $MM of CAPEX vs. Peers (Mbo / $MM CAPEX)(3)(4) The combination of a high-quality, oil-weighted asset base and a low-cost structure results in an industry-leading reinvestment rate Industry Leading Reinvestment Rate and Capital Efficiency
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9 0 4 8 12 16 20 24 0 2 4 6 8 10 12 14 16 18 20 22 24 26 Avg. Days Depth (1,000's of Ft.) 2019 2020 2021 2022 2023 2024 2025 2026 $27.43 $15.91 $38.34 $55.38 $38.47 $34.41 $29.06 $35.88 73% 63% 78% 82% 76% 75% 73% 75% 2019 2020 2021 2022 2023 2024 2025 YTD 2026 % of Realized Price ($/Boe) Cash Margin ($/Boe) LOE Prod. taxes G&T Interest Cash G&A Cash Margin (%) ~1,500' ~2,500' ~2,700' ~3,000' ~3,750' ~4,000' ~4,600' 70 105 130 140 173 193 221 Zipper Frac 2021 2022 2023 2024 2025 YTD 2026 Avg. Ft. / Day Bbls / Day (1,000's) Consistent Track Record of Execution Year over Year Drilling Efficiency Completion Efficiency Shift to Simulfrac Consolidated PD F&D Costs and Recycle Ratio(1) Diamondback continues to drive down costs and improve execution efficiency Unhedged Cash Margins ($ / Boe; % of Realized Price) (2) Source: Company data, filings and estimates. (1) Recycle ratio calculated as unhedged cash margin per Boe including interest expense divided by PD F&D cost per Boe. Please se e note 1 on slide 15 for detail on PD F&D cost calculation. (2) Unhedged cash margin calculated as unhedged realized price per Boe, less cash operating costs including interest per Boe, div ided by the unhedged realized price per Boe. 2.5x 1.6x 4.9x 5.5x 3.9x 3.3x 3.4x $10.87 $9.65 $7.87 $10.10 $9.73 $10.51 $8.52 2019 2020 2021 2022 2023 2024 2025 Recycle Ratio PD F&D ($ / Boe) Value Creation Breakeven (1.0x)
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10 Peer 1 Peer 3 Peer 2 Peer 4 0 2 4 6 8 10 12 14 16 18 0 2 4 6 8 10 12 Cumulative Oil MBO/1,000' Months 2026 Diamondback 2025 Diamondback 2025 Peer 2025 Peer Average 2025 Midland Basin Average 0 5 10 15 20 25 30 0 1 2 3 4 5 6 Peer 2 D Peer 3 Peer 1 Peer 4 Avg. WPS Avg. Zones per Section Avg. Zones Targeted per Section Avg. WPS 40 45 50 55 60 0 1,000 2,000 3,000 4,000 D Peer 1 Peer 2 Peer 3 Peer 4 Avg. Fluid (bbl/ft) Avg. Proppant (lb/ft) Avg. Proppant (lb/ft) Avg. Fluid (bbl/ft) Development Strategy Maximizes Resource and Returns Midland Basin Average Zones Targeted & Wells per Section(1) Midland Basin Average Proppant (lb/ft) & Fluid (bbl/ft)(1) Successful multi-zone co-development execution enables maximum resource extraction, generates consistent well results and minimizes potential child well performance degradation Diamondback’s average well performance consistently ranks among the best in the Midland Basin, despite using the lowest average proppant intensity, drilling near the most wells per section and co-developing near the most zones per section This development strategy, combined with the lowest well costs in the basin, delivers the highest returns per well and DSU, as well as the lowest corporate breakeven Source: Company data and estimates and Enverus. (1) Peer monthly data for 2025 wells. Peers include COP, OXY, XOM and OVV. (2) Midland Basin average well performance for all operators excluding Diamondback. Midland Basin Well Productivity(1) (2)
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11 Net Acres & Economic Locations Overview Midland Basin Delaware Basin Total Net Acres ~808,000 ~94,000 ~902,000 Gross Locations Economic at $50 / Bbl 7,910 944 8,854 2% 2%2% 7% 22% 22% 25% 25% 21% 19% 24% 24% 4% 1% 2025 2026E % of Net TIL Ft. Barnett WCD WCB WCA LS MS / JM US Midland Basin Gross (Net) Locations Economic at $50 / Bbl(1) Delaware Basin Gross (Net) Locations Economic at $50 / Bbl(1) Long Duration, High Quality Inventory Midland Basin Development by Zone (% of Net Lateral Ft.) Diamondback's unmatched inventory depth, with nearly 9,000 locations economic at $50 / Bbl, reflects a consistent co-development strategy and best-in-class inventory quality Source: Company data, filings and estimates. Note: locations based on internal company estimates as of 12/31/2025. Acreage as of 6/30 /2026. (1) Defined as locations that can generate at least a 10% rate of return at $50/ Bbl oil prices, $20/Bbl NGL prices and $3/Mcf gas prices. Assumes 2026 budget capex well costs. (2) Other zones comprised of Clearfork and Wolfcamp C intervals in the Midland Basin and Avalon, 1st Bone Spring, and Wolfcamp C intervals in the Delaware Basin. Shallower Depth Deeper Depth Locations Avg. Lateral US 472 (389) 11,000' MS / JM 1,453 (1,158) 10,800' LS 1,026 (792) 10,700' WCA 1,343 (951) 11,100' WCB 1,391 (921) 10,600' WCD 814 (674) 12,500' Barnett 878 (561) 12,000' Other(2) 533 (409) 9,800' Total 7,910 (5,856) 11,000' Locations Avg. Lateral 2BS 325 (233) 10,200' 3BS 254 (190) 9,700' WCA 117 (73) 9,200' WCB 230 (187) 10,200' Other(2) 18 (3) 6,700' Total 944 (686) 9,900'
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12 6/30/2026 Cash and cash equivalents $462 FANG Debt $11,071 VNOM Debt $1,695 Total Debt $12,766 Net Debt $12,304 Net Debt / Annualized 2Q26 Adjusted EBITDA 0.8x 6/30/2026 Cash(1) $385 Elected commitment $3,000 Standalone Liquidity(1) $3,385 FANG's Consolidated Capitalization FANG's Standalone Liquidity $3.9B $8.8B Debt Maturities Due through 2030 Debt Maturities Due 2031+ Source: Company data, filings and estimates. (1) Excludes Viper. (2) Consolidated net debt, a non-GAAP measure, is defined as total debt (excluding debt issuance costs, discounts, premiums and unamortized basis adjustments) less cash and cash equivalents and restricted cash that has been irrevocably deposited for the redemption of principal amounts of outstanding senior notes. (3) Based on debt maturity profile as of 7/31/2026. (4) Open market repurchase of Senior Notes due 2026. FANG’s Consolidated Total Debt Reduction ($MM) Balance Sheet Summary and Recent Highlights: Investment grade credit ratings: Baa2 (Moody’s), BBB (S&P) and BBB+ (Fitch) Standalone liquidity of ~$3.4 billion(1) Consolidated net debt of ~$12.3 billion(2) Successfully tendered $777 million in principal of 2051 and 2052 Senior Notes for $632 million including accrued interest, or 81.1% of par value and fully repaid the remaining $550 million of our term loan due 2027 The Company’s Credit Agreement was amended to increase total commitments from $2.5 billion to $3.0 billion, extend the maturity to 2031 and reduce applicable interest rates and fees Investment Grade Balance Sheet FANG’s Liquidity and Capitalization ($MM) Weighted Average Maturity of ~12 years(3) (4) $14,667 $14,068 $12,766 $14 $585 $777 $550 $51 $75 $10 ,000 $11 ,000 $12 ,000 $13 ,000 $14 ,000 $15 ,000 $16 ,000 12/31/25 Total Debt Notes Retired Revolver & Term Loan Paydown 3/31/26 Total Debt Tender Offers FANG Term Loan Paid Off OMR VNOM Revolver Draw 6/30/26 Total Debt FANG VNOM
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13 Diamondback Capital Budget ($MM) Operated drilling and completion ~$3,310 2026 Total capital expenditures(2) ~$3,900 Full year 2026 oil production guidance of 522+ Mbo/d (1,000+ Mboe/d) Full year 2026 CAPEX budget of ~$3.9 billion Expect to complete 6.1 – 6.5 million net lateral feet in 2026 with an average lateral length of ~12,900 feet Full Year 2026 Diamondback 2026 Net production – Mboe/d 1,000+ (from 972+) 2026 Oil production – Mbo/d 522+ (from 520+) Unit Costs ($/boe) Lease operating expenses, including workovers $5.90 – $6.40 Cash G&A $0.55 – $0.65 (from $0.55 – $0.70) Non-cash equity-based compensation $0.20 – $0.30 DD&A $13.50 – $14.50 (from $14.00 – $15.00) Interest expense (net of interest income) $0.50 – $0.70 Gathering, processing and transportation $1.40 – $1.60 (from $1.50 – $1.70) Production and ad valorem taxes (% of revenue) ~7% Corporate tax rate (% of pre-tax income) 23% Cash tax rate (% of pre-tax income)(1) 19% – 22% (from 18% – 21%) Full Year 2026 Guidance Source: Company data, filings and estimates. (1) Pre-tax income attributable to the Company is a non-GAAP measure. We are not able to forecast the most directly comparable GAAP measure – Income (loss) before income taxes – due to high variability and difficulty in predicting certain items that affect Income (loss) before income taxes, such as future commodity prices, pace of and costs of developing, producing and operating our interests in oil and natural gas properties, future changes in interest rates and various other business factors impacting our financial results. (2) Includes non-operated drilling and completion, capital workovers, science, infrastructure, midstream and environmental. Diamondback Capital Activity Average lateral length (Ft.) ~12,900’ Net lateral footage completed (1,000’s of Ft.) 6,100’ – 6,500’ Q3 2026 Guidance Diamondback Oil production – Mbo/d 517 – 527 Net production – Mboe/d 995 – 1,015 Total capital expenditures ($MM) $950 – $1,050 Cash taxes ($MM) $400 – $460
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14 Appendix
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15 ($/Boe) 2024 2025 Proved Developed F&D(1) $10.51 $8.52 Reserve Replacement (2) 730% 118% Organic Reserve Replacement (3) 68% 82% F&D Costs Reserves Summary Total Proved Reserve Growth (MMBoe) 3,618 MMBOE Year-end 2025 proved reserves increased 2% year over year to 3,618 MMBoe (1,774 MMBo, 70% PDP) PDP reserves of 2,521 MMBoe; PDP oil reserves of 1,174 MMBo Oil comprised 49% of total proved reserves on 3- stream basis; 56% of total on 2-stream basis Consolidated proved developed F&D for 2025 was $8.52 / Boe 1P Reserves – By Commodity 1P Reserves – By Category 3,618 MMBOE Source: Company data, filings and estimates. (1) PD F&D costs defined as exploration and development costs divided by the sum of reserves associated with transfers from proved undeveloped reserves at prior year-end including any associated revisions in current year and extensions and discoveries placed on production during current year. (2) Defined as the sum of extensions and discoveries, revisions, purchases and divestitures, divided by annual production. (3) Defined as the sum of extensions and discoveries and revisions, divided by annual production. (4) Average annual CAGR since IPO. Oil 49% NGL 27% Natural Gas 24% PDP 70% PUD 30% 131 174 297 929 1,039 1,217 1,661 1,884 1,999 3,361 3,212 157 205 335 992 1,128 1,316 1,789 2,033 2,178 3,557 3,618 3.42 6.04 7.09 8.33 10.06 11.30 12.19 12.22 12.71 -1 4 9 14 19 24 0.0 500 .0 100 0.0 150 0.0 200 0.0 250 0.0 300 0.0 350 0.0 YE15 YE16 YE17 YE18 YE19 YE20 YE21 YE22 YE23 YE24 YE25 FANG Standalone VNOM 1P BOE / Share
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16 11.6 15.8 10.6 16.5 24.9 16.6 14.4 24.3 15.5 21.5 38.8 25.3 FANG Midland Basin Core FANG Midland Basin Barnett Peer Barnett FANG Midland Basin Core FANG Midland Basin Barnett Peer Barnett Cumulative Oil MBO/1,000' Cumulative Oil Equivalent MBOE/1,000' Diamondback has amassed a nearly 200,000 net acre position in the core of the Midland Basin Barnett play, supporting an inventory of 878 gross (561 net) locations Expect to continue to grow position through leasing and strategic joint ventures, with Viper mineral ownership providing an unmatched synergy Full-field development is expected to reduce well costs; a ~20% reduction in well costs – from ~$1,000 per lateral foot today to ~$800 per lateral foot – would bring returns in line with Midland Basin core development Barnett Overview Diamondback Midland Basin Acreage Map(1) 2025 Midland Basin Barnett vs. Midland Basin Core Well Performance(2)(3) Source: Company data, filings and estimates. (1) Diamondback Midland Basin acreage based on internal company estimates as of 6/30/2026. All operators producing Barnett wells as of 6/30/2026 per IHS data. (2) Average daily cumulative well productivity for wells completed by Diamondback with first production in 2025 as of 7/8/2026. Midland Basin core consists of Upper Spraberry, Middle Spraberry, Jo Mill, Lower Spraberry, Dean, Wolfcamp A, Wolfcamp B and Wolfcamp D. (3) Peer Barnett monthly well performance derived from the average of all non-Diamondback operators’ wells with first production in 2025 based on Enverus production data. 6-Month Cum. 12-Month Cum. 2025 6-Month and 12-Month Cumulative Well Performance(2)(3) Diamondback Leasehold Current Extent of Midland Basin Barnett Activity All Operators Producing Barnett Wells 0 5 10 15 20 25 30 0 50 100 150 200 250 300 350 Cumulative Oil MBO/1,000' Days FANG Midland Basin Core FANG Midland Basin Barnett Peer Barnett
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17 Viper Summary Viper’s mineral and royalty interests provide perpetual ownership exposure to high margin, largely undeveloped assets and lower Diamondback’s consolidated breakevens Viper Mineral and Royalty AssetsViper Energy, Inc.: Publicly traded mineral and royalty subsidiary (NASDAQ: VNOM) created by Diamondback ◊ Focused on owning and acquiring minerals and royalty interests in the Permian Basin, with a primary focus on Diamondback-operated acreage ~90,212 net royalty acres in the Permian Basin, ~38% of which are operated by Diamondback(1) Diamondback is incentivized to focus development on Viper’s acreage when possible due to improved consolidated returns ◊ 121 of Diamondback’s 168 2Q 2026 completions were on Viper’s acreage, in which Viper owned a 7.0% average NRI (2) 2Q 2026 average oil production of 65.1 Mbo/d; generated $1.37 / share in distributable cash flow Beyond the ~45% of Viper’s 2026 estimated oil production that Diamondback operates, Viper has diversified exposure to other active operators within the Permian Basin 2Q 2026 Return of Capital: ◊ Base-plus-variable dividend of $0.67 per Class A share; represents a 6.0% annualized yield, based on the July 31, 2026 Class A common share closing price of $44.61 ◊ Repurchased ~3.0 million shares for an aggregate of $132 million (average price of $44.34/share) Viper Market Snapshot Market Cap: $16.4 billion Enterprise Value: $18.0 billion FANG Ownership Value: $6.4 billion (39%) Source: Company data, filings and estimates as of 6/30/2026. Market data as of 7/31/2026. (1) Acreage as of 7/1/2026 and gives effect to Riverbend Acquisition. (2) Well count not normalized to 10,000’.
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18 Equity Method Joint Venture Highlight: Deep Blue In 2025, Diamondback generated ~$1.7 billion of proceeds through its equity-method joint ventures and other non-core asset sales, reflecting disciplined capital allocation and strategic investment execution Deep Blue Asset OverviewDeep Blue Overview Deep Blue is the largest water infrastructure operator in the Midland Basin Established in a joint venture formed in September 2023 between Five Point (70%) and Diamondback (30%) Has approximately 790,000 total dedicated acres, including 672,000 acres from Diamondback In-basin infrastructure supports >800 Mbpd of water demand for a single simulfrac set, enabling industry- leading completion cycle times through integration with FANG’s newly developed continuous pumping program Commercial structure focused on long-term (14+ year average contract life) fee-based contracts in the core of the basin System scale and operational redundancies minimize downtime and facilitate operational flexibility 183 supply pits provide >132MMbbl of storage capacity, underpinning system reliability Future follow-on equity capital of $500 million committed by Five Point and Diamondback Key Statistics 4.6MM permitted bpd capacity 1,920 miles of pipeline 2.0MM bpd produced water Source: Company data, filings and estimates as of 6/30/2026.
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19 Surface Acreage and Potential Uses: Power Generation Diamondback Surface Acreage(1) Diamondback is the Premier Partner Diamondback Surface Acreage Power Plant Data Center Hyperscaler / Data Center Partners IPP Partner Provide Land Supply Natural Gas Repurchase Power Power Provide Water Diamondback Surface Acres: 65,000 Provides site for power plant and data center construction 1 Supplies natural gas for power generation 2 Purchases a portion of power for internal operations 3 Provides water for data center cooling 4 Source: Company data, filings and estimates. (1) As of 6/30/2026.
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20 Current Hedge Summary: Oil Source: Company data and filings as of 7/31/2026. Consolidated Crude Oil Hedges (Bbl / day; $ / Bbl) Diamondback’s hedge strategy is to maximize upside exposure to commodity prices while protecting the extreme downside Crude Oil Hedges Q3 2026 Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 Long Puts - Brent 20,000 10,000 5,000 – – – Price / Premium $52.50 / -$1.60 $55.00 / -$1.33 $55.00 / -$1.40 – – – Long Puts - MEH 95,000 70,000 50,000 35,000 5,000 – Price / Premium $50.53 / -$1.43 $50.71 / -$1.33 $50.00 / -$1.31 $50.00 / -$1.35 $50.00 / -$1.29 – Long Puts - WTI 190,000 170,000 100,000 65,000 25,000 – Price / Premium $52.57 / -$1.30 $50.59 / -$1.28 $50.00 / -$1.34 $50.00 / -$1.34 $50.00 / -$1.41 – Total Long Puts 305,000 250,000 155,000 100,000 30,000 – Put Spreads - WTI 15,000 – – – – – Long Put / Short Put $50.00 / $55.00 – – – – – 85,000 85,000 20,000 20,000 10,000 10,000 $1.09 $1.09 $1.51 $1.51 $1.01 $1.01 Basis Puts - WTI / Brent 290,000 290,000 – – – – Spread / Deferred Premium -$42.76 / -$1.52 -$41.03 / -$1.44 – – – – 150,000 150,000 – – – – $2.89 $2.89 – – – – Basis Swaps - WTI Roll Swaps - WTI
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21 Current Hedge Summary: Natural Gas Consolidated Natural Gas Hedges (Mmbtu / day; $ / Mmbtu) Current outright gas position: >60% of estimated FY 2026 gas production protected Current basis position: Waha/HSC basis protection covering ~55% of estimated FY 2026 gas production ~30% of estimated 2026 production receives non-Waha pricing Source: Company data and filings as of 7/31 /2026. Diamondback’s hedge strategy is to maximize upside exposure to commodity prices while protecting the extreme downside Natural Gas Hedges Q3 2026 Q4 2026 FY 2027 FY 2028 Costless Collars - Henry Hub 840,000 840,000 720,000 50,000 Floor / Ceiling $2.87 / $6.35 $2.87 / $6.35 $2.88 / $6.37 $2.60 / $5.78 650,000 650,000 370,000 – ($1.87) ($1.75) ($1.27) – 100,000 100,000 300,000 90,000 ($0.35) ($0.35) ($0.31) ($0.34) Basis Swaps - HSC Basis Swaps - Waha
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22 Adjusted EBITDA: Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial stat ements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as net income (loss) attributable to Diamondback Energy, Inc., plus net income (loss) attributable to non- controlling interest ("net income (loss)") before non -cash (gain) loss on derivative instruments, net, interest expense, net, depreciation, depletion, amortization and accretion, depreciation and interest expense related to equity method investments, (gain) loss on extinguishment of debt, impairment of oil and natural gas properties, non- cash equity-based compensation expense, capitalized equity-based compensation expense, other non- cash transactions and provision for (benefit from ) income taxes, if any. Adjusted EBITDA is not a measure of net income as determined by United States generally accepted accounting principles ("GAAP"). Management believes Adjusted EBITDA is useful because the measure allows i t to evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income (loss) to determine Adjusted EBITDA because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Further, the Company excludes the effects of significant transactions that may affect earnings but are unpredictable in nature, timing and amount, although they may recur in different reporting periods. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of the Company’s operating performance. Certain items excluded from Adj usted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets. The Com pany’s computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts. The following tables present a reconciliat ion of the GAAP financial measure of net income (loss) attributable to Diamondback Energy, Inc. to the non- GAAP financial measure of Adjusted EBITDA: Non-GAAP Definitions and Reconciliations (in millions) Three Months Ended June 30, 2026 Six Months Ended June 30, 2026 Net income (loss) attributable to Diamondback Energy, Inc. $ 1,882 $ 1,907 Net incom e (loss) attributable to non-controlling interest 173 292 Net income (loss) 2,055 2,199 Non-cash (gain) loss on derivative instrum ents, net 64 80 Interest ex pense, net 56 119 Depreciation, depletion, amortization and accretion 1,272 2,565 Depreciation and interest ex pense related to equity m ethod investm ents 12 26 (G ain) loss on ex tinguishm ent of debt (134) (133) Im pairm ent of oil and natural gas properties — 1,400 Non-cash equity-based com pensation ex pense 33 64 Capitalized equity-based com pensation ex pense (9) (18) Other non-cash transactions 11 27 Provision for (benefit from ) incom e tax es 580 612 Cons ol i dated Adjus ted EB ITDA $ 3,940 $ 6,941 Less: Adjustm ent for non-controlling interest 391 688 Adjusted EBITDA attributable to Diamondback Energy, Inc. $ 3,549 $ 6,253 Source: Company data and filings.
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23 Operating Cash Flow before Working Capital Changes and Free Cash Flow: Operating cash flow before working capital changes, which is a non- GAAP financial measure, represents net cash provided by opera ting activities as determined under GAAP without regard to changes in working capital. The Company believes operating cash flow before working capital changes is a useful measure of an oil and natural gas company’s ability t o generate cash used to fund exploration, development and acquisition activities and service debt or pay dividends. The Company also uses this measure because changes in working capital relate to the timing of cash receipts and di sbursements that the Company may not control and may not relate to the period in which the operating activities occurred. This allows the Company to compare its operating performance with that of other companies without regard to financing methods and capital structure. Free Cash Flow, which is a non- GAAP financial measure, is cash flow from operating activities before changes in working capital in excess of cash capital expenditures. Adjusted Free Cash F low, which is a non-GAAP financial measure, is Free Cash Flow before the tax impact from divestitures, merger and transaction expenses, costs of early termination of derivatives and settlements of any treasury locks (if any). The Company believes that Free Cash Flow and Adjusted Free Cash Flow are useful to investors as they provide a measure to compare both cash flow fro m operating activities and additions to oil and natural gas properties across periods on a consistent basis, adjusted, as applic able, for non-recurring impacts from divestitures, merger and transaction expenses, the early termination of derivative contracts and settlements of treasury locks . These measures should not be considered as an alternative to, or more meaningful than, net cash provided by operating activ ities as an indicator of liquidity. The Company's computation of operating cash flow before working capital changes, Free Cash Flow and Adjusted Free Cash Flow may not be comparable to other similarly titled measures of other companies. The Company uses Free Cash Flow to reduce debt, as well as return capital to stockholders as determined by the Board of Directors. The following tables present a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non- GAAP measure of operating cash flow before working capital changes and to the non- GAAP measures of Free Cash Flow and Adjusted F ree Cash Flow: Source: Company data and filings. (1) Includes $4 million of Viper's transaction expenses related to the Sitio Acquisition for the six months ended June 30, 2026. Non-GAAP Definitions and Reconciliations (in millions) Three Months Ended June 30, 2026 Six Months Ended June 30, 2026 Net cash prov ided by operating activ ities $ 3,589 $ 5,417 Less: Changes in cash due to changes in operating assets and liabilities: Accounts receivable 216 (563) Accounts payable and accrued liabilities 53 (204) Income tax es payable (287) — Revenues and royalties payable 254 324 Other 27 (104) Total working capital changes 263 (547) Operating cash flow before w orking capital changes 3,326 5,964 Additions to oil and natural gas properties (996) (1,929) Total Cash CAPEX (996) (1,929) Free Cash Flow 2,330 4,035 Merger and transaction ex penses (1) 1 6 Early term ination of derivatives — 27 Adjusted Free Cash Flow $ 2,331 $ 4,068
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24 Net Debt: The Company defines the non-GAAP measure of net debt as total debt (excluding debt issuance costs, discounts, premiums and unamortized basis adjustments) less cash and cash equivalents and restricted cash that has been irrevocably deposited for the redemption of principal amounts of outstanding senior notes. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. The Company believes this metric is useful to analysts and investors in determining the Company's leverage position because the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. Source: Company data and filings. (1) Excludes debt issuance costs, discounts, premiums and unamortized basis adjustments. Non-GAAP Definitions and Reconciliations (in millions ) June 30, 2026 Net Q2 Principal Borrowings/ (Repayments) M arch 31, 2026 December 31, 2025 Sep temb er 30, 2025 June 30, 2025 Diam ondback Energy, Inc.(1) $ 11,071 $ (1,377) $ 12,448 $ 12,462 $ 13,792 $ 14,212 V iper Energy, Inc.(1) 1,695 75 1,620 2,205 2,640 1,105 Total debt 12,766 (1,302) 14,068 14,667 16,432 15,317 Cash and cash equivalents (462) (174) (104) (539) (219) Net debt $ 12,304 $ 13,894 $ 14,563 $ 15,893 $ 15,098
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25 Cash Return on Capital Invested: Cash Return on Capital Invested, which is a non-GAAP measure, is calculated as debt-adjusted cash flow from operations before working capital changes divided by capital invested. Capital invested is calculated as total assets plus accumulated DD&A minus cash and cash equivalents minus non-interest-bearing current liabilities. Non-GAAP Definitions and Reconciliations (in millions) 12/31/2015 12/31/2016 12/31/2017 12/31/2018 12/31/2019 12/31/2020 12/31/2021 12/31/2022 12/31/2023 12/31/2024 12/31/2025 Debt-Adjusted Cash Flow Net Cash Provided by (used in) operating activities ("CFO") $332 $889 $1,565 $2,739 $2,118 $3,944 $6,325 $5,920 $6,413 $8,758 - Working Capital Changes ("WC") ($16) ($48) $6 ($167) $97 $36 ($199) $296 ($96) ($314) CFO Before WC $348 $937 $1,559 $2,906 $2,021 $3,908 $6,524 $5,624 $6,509 $9,072 Interest Expense, net $41 $41 $87 $172 $197 $199 $159 $159 $135 $244 Statutory Rate 35% 35% 21% 21% 21% 21% 21% 21% 21% 21% After-Tax Interest Expense $27 $26 $69 $136 $156 $157 $126 $126 $107 $193 CROCI Numerator: CFO before WC + After-Tax Interest Expense $374 $963 $1,628 $3,042 $2,177 $4,065 $6,650 $5,750 $6,616 $9,265 Capital Invested Total Assets $2,751 $5,350 $7,771 $21,596 $23,531 $17,619 $22,898 $26,209 $29,001 $67,292 $71,059 + Accumulated DD&A $1,417 $1,836 $2,161 $2,774 $5,003 $12,314 $13,545 $14,844 $16,429 $19,208 $27,782 − Cash & Cash Equivalents $0 $1,667 $112 $215 $123 $104 $654 $157 $582 $161 $104 − Non-Interest-Beari ng Current Li abi l i ti es $141 $209 $577 $1,019 $1,263 $1,045 $1,393 $1,706 $2,108 $3,911 $3,837 Year-End Capital Invested $4,026 $5,310 $9,243 $23,136 $27,148 $28,784 $34,396 $39,190 $42,740 $82,428 $94,900 CROCI Denominator: Average Capital Invested (Beg + End ÷ 2) -- $4,668 $7,276 $16,190 $25,142 $27,966 $31,590 $36,793 $40,965 $62,584 $88,664 CROCI (%): CROCI Numerator ÷ CROCI Denominator 8.0% 13.2% 10.1% 12.1% 7.8% 12.9% 18.1% 14.0% 10.6% 10.4% Source: Company data, filings and estimates.
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