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Investor Presentation November 2026
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2 Forward Looking Statements This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which involve risks, uncertainties, and assumptions that could cause the results to differ materially from such statements. All statements, other than statements of historical fact, including statements regarding Viper’s: future performance; business strategy; future operations; estimates and projections of operating income, losses, costs and expenses, returns, cash flow, and financial position; production levels on properties in which Viper has mineral and royalty interests; developmental activity by other operators; reserve estimates and Viper’s ability to replace or increase reserves; the anticipated benefits from the Sitio Acquisition or other strategic transactions (including the Riverbend Acquisition, 2026 Drop Down, McElroy Ranch Acquisition, Pending Buckhorn Acquisition or any other acquisitions or divestitures); and plans and objectives (including Diamondback’s plans for developing Viper’s acreage and Viper’s cash dividend policy and common stock repurchase program) 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 Viper are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Although Viper 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 its control. Accordingly, forward-looking statements are not guarantees of Viper’s future performance and the actual outcomes could differ materially from what Viper expressed in its forward-looking statements. Factors that could cause the outcomes to differ materially include (but are not limited to) the following: changes in supply and demand levels for oil, natural gas and natural gas liquids and the resulting impact on the price for those commodities; the impact of public health crises, including epidemic or pandemic diseases and any related company or government policies or actions; 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, or instability in the financial sector; regional supply and demand factors, including delays, curtailment delays or interruptions of production on our mineral and royalty acreage, or governmental orders, rules or regulations that impose production limits on such acreage; 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 and changing political and social perspectives on climate change and other environmental, social and governance factors; risks from our cash dividend policy and uncertainties over our future dividends; restrictions on the use of water, including limits on the use of produced water by our operators and a moratorium on new produced water well permits 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; changes in U.S. energy, environmental, monetary and trade policies, including with respect to tariffs or other trade barriers and any resulting trade tensions; conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development by our limited number of operators and our ability to replace operators in time of bankruptcy or default; changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services impacting our operators; the inherent uncertainties over our estimated reserves, the development of our proved undeveloped reserves or the yield from project areas on our properties; the geographical concentration of our producing properties and reserves in the Permian Basin and in a small number of producing horizons; changes in safety, health, environmental, tax and other regulations or requirements impacting us or our operators (including those addressing air emissions, water management, or the impact of global climate change); security threats, including cybersecurity threats and disruptions to our business from breaches of Diamondback’s information technology systems, or from breaches of information technology systems of our operators or 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 impacting our operators; severe weather conditions and natural disasters; geopolitics, regional conflicts, acts of war or terrorist acts and the governmental or military response thereto; changes in the financial strength of counterparties to the revolving credit facility and hedging contracts of our operating subsidiary; our substantial indebtedness and changes in our credit rating; failure to develop or acquire additional reserves and identify, complete or integrate acquisitions such as the Riverbend Acquisition, McElroy Ranch Acquisition or Pending Buckhorn Acquisition; our operational dependence on, and control by, Diamondback and potential conflicts of interest thereof; and other risks and factors discussed in Viper’s Annual Report on Form 10-K for the year ended December 31, 2025 and subsequent periodic filings with the SEC, including its Forms 10-K, 10-Q and 8-K, and other filings Viper makes with the SEC, which can be obtained free of charge on the SEC’s web site at http://www.sec.gov. In light of these factors, the events anticipated by Viper’s forward-looking statements may not occur at the time anticipated or at all. Moreover, new risks emerge from time to time. Viper 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. Viper does not intend to, and disclaims any obligation to, update or revise any forward-looking statements unless required by applicable law. Non-GAAP Financial Measures Adjusted EBITDA and Adjusted EBITDA margin are supplemental non-GAAP (as defined below) financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as net income (loss) attributable to the Company, plus net income (loss) attributable to non-controlling interest (“net income (loss)”) before interest expense, net, non-cash share-based compensation expense, depreciation, depletion and amortization, impairment, non-cash (gain) loss on derivative instruments, provision for (benefit from) income taxes and other non-cash or non-recurring operating expenses. The Company defines Adjusted EBITDA margin as Adjusted EBITDA divided by total operating income. Adjusted EBITDA and Adjusted EBITDA margin are not measures of net income as determined by United States’ generally accepted accounting principles (“GAAP”). Management believes Adjusted EBITDA and Adjusted EBITDA margin are useful because they allow them 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. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income, royalty income, cash flow from operating activities or any other measure of financial performance or liquidity presented as determined in accordance with GAAP. Adjusted EBITDA margin should not be considered as an alternative to, or more meaningful than, net income margin, gross margin, or any other measure of financial performance or liquidity presented as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDA and Adjusted EBITDA margin 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, none of which are components of Adjusted EBITDA or Adjusted EBITDA margin. 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 operating assets and liabilities. The Company believes operating cash flow before working capital changes is a useful measure of the Company’s ability to generate cash to fund acquisition activities, service debt or pay dividends. The Company also uses this measure because changes in operating assets and liabilities 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. The Company defines Free Cash Flow, which is a non-GAAP financial measure, as operating cash flow before working capital changes in excess of capital expenditures. The Company defines Free Cash Flow margin as Free Cash Flow divided by total operating income. The Company believes that Free Cash Flow and Free Cash Flow margin are useful to investors as they provide a measure to compare cash flow from operating activities across periods on a consistent basis. These measures should not be considered as alternatives to, or more meaningful than, net cash provided by operating activities as an indicator of liquidity. The Company's computations of Free Cash Flow and Free Cash Flow margin may not be comparable to other similarly titled measures of other companies. The Company defines the non-GAAP measure of net debt as debt (excluding debt issuance costs, discounts and premiums) less cash and cash equivalents. 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. Furthermore, this presentation includes or references certain forward‐looking, non‐GAAP financial measures, such as Adjusted EBITDA, Adjusted EBITDA margin, operating cash flow before working capital changes, Free Cash Flow, Free Cash Flow margin, net debt and certain related estimates regarding future performance, results and financial position. Because Viper 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 any future impairments, future changes in working capital, future commodity prices, pace of development and production of our mineral interests, and factors impacting the Company’s ownership of Viper Energy Partners LLC such as repurchases of our Class A common shares or conversions to Class B common shares and/or OpCo unit conversion to Class A common shares. 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 Viper’s forecasted financial performance to the forecasted financial performance of other companies in the industry.
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3 Viper Energy Overview Source: Company data and filings. Market data based on VNOM’s closing price of $47.68 on 10/30/2026. Acreage data as of 9/30/2026. Viper Assets Market Snapshot NASDAQ Symbol: VNOM Market Cap: $17.6 billion Net Debt(1)(2): $2.4 billion / Liquidity (1)(2): $1.2 billion Enterprise Value: $20.0 billion Share Count: 368.3 million(3) Dividend Yield: 4.2% (MRQA) Net Royalty Acreage: ~98,098 (~38% FANG-operated) (1) Net Debt and Liquidity as of 9/30/2026. (2) See Non-GAAP definitions and reconciliations in the appendix. (3) Share count as of 9/30/2026. Includes 6.7 million OpCo units that have the option to be granted an equal number of shares of Class B common stock. Highlights Unique Relationship with a Leading Operator Diamondback owns ~40% of the equity and operates ~38% of Viper’s net royalty acres, reducing uncertainty around pace of development Irreplicable Permian Footprint Interest in ~50% of horizontal wells drilled in the Permian Basin; exposure to large, well-capitalized public and private operators High-Margin Free Cash Flow with No Capex No lease operating expenses, drilling and completion capex or direct exposure to cost inflation; Adjusted EBITDA margin of ~90% Durable and Growing Dividend $2.00 / share annual base dividend protected to ~$30 / bbl WTI; retained cash flow funds share buybacks, debt paydown or accretive M&A Investment Grade Balance Sheet Only investment grade pure-play oil and gas minerals company
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4 Third Quarter 2026 Highlights Source: Company data. Financial and operating data for the three months ended 9/30/2026. (1) See Non-GAAP definitions and reconciliations in the appendix. (2) Annualized Q3’26 dividend of $2.00 per Class A share divided by VNOM closing price of $47.68 on 10/30/2026. 69,076 bo/d Average Daily Oil Production 141,152 boe/d total +13% YoY Oil Production per MM Share Q3 2026 vs. Q3 2025 $596MM Adjusted EBITDA(1) 90% EBITDA margin(1) $520MM Free Cash Flow(1) 79% FCF margin(1) $0.50 / share Declared Cash Dividend 4.2% annualized yield(2) ~2.1MM Class A Shares Repurchased ~$90 million at $43.01 average price
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5 Jan 2015 Jan 2016 Jan 2017 Jan 2018 Jan 2019 Jan 2020 Jan 2021 Jan 2022 Jan 2023 Jan 2024 Jan 2025 Jan 2026 Viper's Assets as of 9/30/26 Total Permian (Midland and Delaware Basins) A Decade of Outgrowing the Permian Basin Source: Company data and Enverus. Data from January 2015 to June 2026. Note: Viper Avg. Daily Oil Production represents net average daily oil production from January 2015 through June 2026 of the wells that Viper owned an interest in as of 9/30/26. Total Permian represents gross average daily oil production from all wells in the Midland and Delaware Basins. Normalized Average Daily Oil Production Growth since 2015 Viper’s Current Assets Have Outpaced Permian Basin Oil Growth ~3x since 2015 Average daily oil production on assets that Viper owned at the end of Q3 2026 have grown at a significantly higher rate than the overall Permian Basin Outsized growth driven by high-quality assets, unique relationship with Diamondback and execution on disciplined and returns-focused acquisition strategy
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6 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0 20 40 60 80 100 120 140 160 180 200 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026E Cash Margin (% of Realized Price)(2) Average Production per Million Shares(1) Production per MM Shares Cash Margin (%) Long-Term Track Record of Per Share Growth Source: Company data, estimates and filings. (1) Production per million shares calculated as average daily oil production divided by weighted average million shares outstandi ng by quarter. (2) Cash margins defined as unhedged realized price per boe less production & ad valorem taxes, cash G&A and interest expense div ided by unhedged realized price per boe. (3) Assumes midpoint of the 2026 oil production guidance range. Share count as of 9/30/2026. Growth in Per Share Metrics with Consistently High Cash Margins Creates Long-Term Value for Stockholders Viper is focused on increasing per share value for stockholders and maximizing long-term returns A combination of organic growth, accretive acquisitions and an opportunistic share repurchase program have driven production per share to a Company record With Viper’s low cash G&A and limited other operating expenses, increase in production leads directly to lower per unit costs and increased returns for stockholders Oil Production per Million Shares and Cash Margin Since IPO (1) (2) (3) ~17% CAGR from 2014 – 2025; 4.5x Increase Increase From Original Guidance
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7 ~$1,400 ~$1,600 ~$1,850 ~$2,100 ~$2,300 6.4% 7.4% 8.4% 9.3% 10.3%7.4% 8.5% 9.6% 10.7% 11.7% $60 / Bbl $70 / Bbl $80 / Bbl $90 / Bbl $100 / Bbl Assumptions Efficient Free Cash Flow Generation Source: Company data and filings. Financial data as of 9/30/2026. Per share metrics assume 194.9 million Class A shares outstanding, pro forma for the Pending Buckhorn Acquisition. Yield based on share closing price of $47.68 per Class A share on 10/30/2026. Note: Includes current hedges, which assume Waha strip pricing as of 10/30/2026. (1) See Non-GAAP definitions and reconciliations in the appendix. FCF Yield (EV) and FCF Yield (Market Cap) are calculated as FCF divided by Enterprise Value and Market Cap, respectively. (2) Roughly approximates total interest expense based on Q3 ‘26 actuals, pro forma for the Pending Buckhorn Acquisition and 4.900% fixed interest payments on $500 million Sr. Notes due 2030, 5.700% fixed interest payments on $1.1 billion Sr. Notes due 2035, 5.433% interest on ending balance on revolving credit facility at 9/30/2026 pro forma for the Pending Buckhorn Acquisition and a 0.20% non - use fee on the undrawn capacity of the revolving credit facility. (3) Percent of pre-tax income attributable to Viper Energy Class A stockholders. Illustrative Annualized Q4’26 Free Cash Flow ($MM) and Free Cash Flow per Class A Share(1) 70.0 – 71.0 Mbo/d Oil Production 141.5 – 143.5 Mboe/d Total Production $38 Million Cash G&A 7% of Revenue Prod. & Ad Valorem Taxes 27% of WTI / $1.00/MMBtu Realized NGL / Gas Prices ~99% % of WTI Realized $140 Million Interest Expense(2) Viper is uniquely positioned to generate high margin free cash flow through commodity price cycles with high leverage to increasing oil prices; hedging strategy provides mostly uncapped exposure to upside At $80 WTI and production held flat at the midpoint of Q4 2026 guidance, Viper is expected to generate ~$1.85 billion of annualized free cash flow, or ~$4.55 per Class A share, an approximately 9.6% yield; at $100 WTI, free cash flow rises to ~$2.31 billion, or ~$5.60 per Class A share, an approximately 11.7% yield FCF Yield (EV) FCF Yield (Market Cap)FCF 28.5% Effective Cash Tax Rate(3) ~$3.50/sh. ~$4.05/sh. ~$4.55/sh. ~$5.10/sh. ~$5.60/sh.
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8 100% 91% 74% 62% 54% 50% 46% $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 Breakeven (<$30 WTI) $30 WTI $40 WTI $50 WTI $60 WTI $70 WTI $80 WTI Free Cash Flow ($Bn) $2.00 Annual Base Dividend Retained Cash 11.0% 15.7% 17.7% 10.5% 7.3% 10.8% 22.8% 18.0% 13.5% 11.3% 12.4% 0% 5% 10% 15% 20% 25% 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 YTD 2026 CROCI vs. WACC (%) WACC CROCI Durable Return of and Return on Capital Source: Company data, Bloomberg data, filings and estimates. Estimated Coverage of Annual Base Dividend at Various Oil Prices(1) Cash Return on Capital Invested (CROCI)(2) vs. Weighted Average Cost of Capital (WACC) (1) Unhedged 2027E using outstanding share count of ~370.2 million (gives effect to the Pending Buckhorn Acquisition and includes 6.7 million Op Co Units that have the option to be granted an equal number of shares of Class B common stock). (2) CROCI is calculated as Cash From Operations (CFO) ÷ average adjusted Invested Capital (total assets + cumulative impairments - non-interest-bearing current liabilities). Dividend Built to Last ♦ Base dividend of $2.00 per Class A share annually, a ~4.2% annualized yield, based on the October 30, 2026 Class A common share closing price of $47.68 ♦ Committed to grow the base dividend through the cycle ♦ Five base dividend increases since initiating in Q2 ’22; Board approved annual base dividend of $2.00 starting in Q3 ’26 is 2x greater than initial base dividend ~4 years ago ♦ Dividend fully protected down to ~$30 / bbl WTI Returns Exceed Cost of Capital ♦ Return on capital exceeds cost of capital through the cycle, compounding per-share value over time Flexibility to Create Value ♦ Increased flexibility by retaining excess cash flow allows Viper to continue opportunistic share repurchases, reduce debt and pursue a disciplined M&A strategy, all of which are expected to compound value for stockholders over the long term
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9 Creating Long-Term Value Through Acquisitions Source: Company data, estimates and Bloomberg. Includes 28 transactions closed January through October 2026 and the Pending Buckhorn Acquisition, expected to close in the fourth quarter of 2026. Viper’s Acquisition Strategy What the Strategy Delivers 2026 Acquisitions at a Glance (1) Off-market share measured by purchase price. (2) Total consideration includes equity (Class A shares / OpCo units) valued at issuance; includes $49MM of deferred consideratio n for McElroy Ranch. (3) Net 100% royalty interest horizontal wells / locations normalized to 10,000 -foot laterals; excludes ~97 net vertical wells; % un developed based on Viper’s estimated net asset value. (4) Pro forma net debt / most recent quarter annualized Adj. EBITDA as of 9/30/2026, giving effect to the Pending Buckhorn Acquis ition; see page 14 and Non-GAAP reconciliations in the appendix. 29 transactions closed or signed in 2026 ~$1.7 B aggregate purchase price ~79% of capital deployed in proprietary / off- market deals(1) ~13,400 net royalty acres acquired ~107 net inventory locations added(3) ~$126,000 average price per net royalty acre(2) Disciplined, Off-Market Consolidation Builds Inventory Duration and Long-Term Stockholder Returns Proprietary sourcing: Diamondback’s operating footprint and Viper’s data provide a unique view of off-market opportunities 28 of 29 transactions sourced off-market; ~79% of capital deployed in proprietary deals(1) Returns-focused underwriting: consistent underwriting standards applied to every deal, with a bias toward undeveloped inventory Compelling returns to stockholders over time: acquisitions that consistently exceed Viper’s cost of capital Inventory replenishment: prioritize undeveloped, high-NRI acreage under top-tier operators ~107 net 10,000’ undeveloped locations added; ~77% of 2026 acquired value is undeveloped(3) Financial discipline: underwritten at conservative pricing while protecting the investment grade balance sheet ~76% cash-funded while maintaining ~1.1x pro forma leverage(4); Class A shares, OpCo units and deferred consideration used selectively where it suits the seller Diamondback alignment: drop downs and shared development visibility help ensure acquired inventory converts to production Maintain high exposure to Diamondback completions with a concentrated NRI
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10 Acquisition Overview: Riverbend, Drop Down & Buckhorn Source: Company data and estimates. Riverbend closed 7/1/2026; Drop Down closed 9/1/2026; Buckhorn expected to close fourth quarter 2 026, subject to customary closing conditions. Net Royalty Acres by County Key Acquisition Statistics Key Takeaways (1) Purchase price / annualized cash flow for the quarter after the effective date; $MM / location excludes allocated producing v alue. (2) Net 100% royalty interest wells / locations normalized to 10,000’ laterals; % undeveloped based on Viper’s estimated net asset value of acquired assets. (3) Net production for each transaction’s effective month. (4) Includes equity consideration (Class A shares / OpCo units) valued at issuance. Excludes transactions costs. Disciplined Valuation: Acquired at a combined ~7.3x implied cash flow multiple(1) and ~$10.6MM per net undeveloped location(1) Funded with $619MM of cash and $410MM of equity, including the all-equity Drop Down Inventory Replenishment: Added 60.0 net undeveloped locations(2) 66% undeveloped(2), weighting value toward future development Strategic Fit and Cash Flow: ~75% (Riverbend) and ~80% (Buckhorn) overlap with existing Viper acreage Adds ~4,325 bo/d of net production(3) Riverbend Drop Down Buckhorn Total Purchase Price ($MM)(4) $505 $164 $360 $1,029 Cash/Equity ($MM)(4) $339/$166 –/$164 $280/$80 $619/$410 Net Royalty Acres 2,772 1,004 1,552 5,328 $ / NRA $182,200 $163,300 $232,000 $193,100 Production (bo/d)(3) ~2,200 ~625 ~1,500 ~4,325 Net Undeveloped Locations(2) 33.9 8.7 17.4 60.0 % Undeveloped(2) 66% 77% 61% 66% Implied Cash Flow Multiple(1) 7.1x 8.1x 7.3x 7.3x $MM / Net Undev. Location(1) $9.1 $12.3 $12.9 $10.6 Delaware Basin Midland Basin
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11 83 (Oil, BO/ft) 52 (Oil, BO/ft) 134 100 Barnett Spraberry/ Wolfcamp Acquisition Overview: McElroy Ranch Source: Company data and estimates. McElroy Ranch Acquisition closed in September 2026; acreage and inventory data as of closing, sub ject to customary post-closing adjustments. Net Royalty Interest (NRI) by Unit Key Acquisition Statistics Acquisition Highlights Offset Well Performance (1) Average estimated ultimate recovery of offsetting wells with at least 12 months of production data. (2) Expected net 100% royalty interest locations normalized to 10,000’ laterals. (3) Total consideration less allocated value of producing wells, divided by net undeveloped locations. Transaction Overview: Closed in September 2026 for $529MM (2 separate transactions) ~7,359 NRA; concentrated ~12% NRI across ~60,000 gross acres in an expected core geologic fairway of Barnett development in the western Midland Basin Inventory and Asset Quality: 96% undeveloped with an expected 40.9 net 10,000’ inventory locations; only 21 currently producing gross (1.7 net) horizontal locations across the entire Ranch Offsetting Barnett wells indicate an estimated ultimate recovery (EUR) of ~80 bo/ft (1) Diamondback operates an estimated 15% of net undeveloped inventory; Chevron, Firebird, Summit, Apache and ExxonMobil operate the remainder of the Ranch Production: Approximately 400 bo/d from existing vertical wells; forecasted peak oil production on the Ranch in the range of 5,000 bo/d over the next decade Total Consideration $529MM Net Royalty Acres ~7,359 $ / NRA ~$71,900 Net Undeveloped Locations(2) 40.9 % Undeveloped 96% $MM / Net Undeveloped Location(3) $11.3 EUR Per Foot (Boe/ft)(1) NPV-10 ($MM) & IRR At $70 oil / $3.00 gas / $20 NGL realized prices $12.2 $7.5 64% 97% Barnett Spraberry/ Wolfcamp
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12 5.6 6.7 7.0 9.7 9.9 11.2 13.3 14.6 23.7 7.9 12.1 14.0 16.3 16.6 19.4 22.0 27.2 49.0 - 10.0 20.0 30.0 40.0 50.0 60.0 70.0 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026E Diamondback Owns ~40% of Viper’s Outstanding Common Stock and is Expected to Continue to Drive Meaningful Long-Term Oil Production Growth from the Company’s Acreage Development Detail Unique Relationship with the Premier Permian Operator FANG-Operated % FANG-Operated Source: Company data and filings. Third Party-Operated Diamondback-Operated vs. Third Party-Operated Permian Oil Production (Mbo/d) 55% 50% 60% 60% 58% 60% 54%71% Economic alignment and significant exposure to Diamondback’s planned completions expected to continue to drive production growth Diamondback relationship continues to be strategic and meaningful to Viper’s growth, complemented by increasing exposure to top tier third-party operators 45%48%
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13 0 2 4 6 8 10 12 14 16 - 250 500 750 1,000 1,250 1,500 Q2 '23 Q3 '23 Q4 '23 Q1 '24 Q2 '24 Q3 '24 Q4 '24 Q1 '25 Q2 '25 Q3 '25 Q4 '25 Q1 '26 Q2 '26 Q3 '26 Net Normalized Viper Wells(2) Normalized Wells(1) Viper’s Current Assets Have Captured Almost Half of All Third-Party Operator Activity in the Permian Basin(1) Since the Start of 2023 Broad Exposure to Third-Party Permian Operators Source: IHS, Company data and estimates . (1) Normalized wells drilled calculated as total horizontal lateral feet drilled divided by 10,000. Metrics are based on horizont al wells drilled in core Permian Basin counties, which include Culberson, Dawson, Ector, Glasscock, Howard, Loving, Martin, Midland, Pecos, Reagan, Reeves, Upton, Ward and Winkler counties in Texas a nd Eddy and Lea counties in New Mexico. (2) Net normalized Viper wells calculated as normalized wells multiplied by average Viper net revenue interest. In addition to its unique relationship with Diamondback, Viper has broad exposure to other third-party operators in the core of the Permian Basin Viper’s high quality royalty acreage operated by third parties has consistently captured a significant amount of all activity across the Permian Basin The combination of concentrated exposure to Diamondback activity and broad exposure to all other activity in the Permian Basin will support Viper’s production over the coming years Permian Basin(1) Normalized Wells Drilled (Excluding Diamondback) Average NRI: 1.6%1.2% 1.4% 1.5% 1.3% 1.6% 1.0% 1.3% 1.4% 1.2% 1.7% Viper Ownership No Viper Ownership Net Normalized Viper Wells(2) 2.0% 1.4% 1.3%
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14 Buckhorn Acquisition(4) VNOM Capitalization & Leverage 9/30/2026 Adj. PF 9/30/2026 Cash $10 $ - $10$0 Revolving Credit Facility 810 262 1,072 4.900% Sr. Notes due 2030 500 - 500 5.700% Sr. Notes due 2035 1,100 - 1,100 Total Debt $2,410 $262 $2,672 Net Debt (1) $2,400 $262 $2,662 Net Debt / MRQA Adj. EBITDA (1)(4) 1.0x 0.1x 1.1x VNOM Liquidity 9/30/2026 Adj. PF 9/30/2026 Cash $10 - $10 Revolving Credit Facility 810 262 1,072 Commitments 2,000 - 2,000 Liquidity $1,200 ($262) $938 $500 $1,072 $1,100 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Viper Debt Maturity Profile ($MM)(5) ♦ Investment grade credit ratings ♦ Revolving credit facility of $2.0 billion with $810 million drawn on revolver as of 9/30/2026; matures in 2031 ♦ Net debt(1) as of 9/30/2026 of $2.4 billion ($2.7 billion PF) ♦ Liquidity as of 9/30/2026 of $1.2 billion ($0.9 billion PF) ♦ Hedge to maximize upside exposure to commodity prices while protecting against the extreme downside Financial Overview and Guidance Balance Sheet and Hedging Viper Capitalization ($MM) Guidance(2) Q4 ‘26 Net Oil Production - Mbo/d 70.00 - 71.00 Q4 ‘26 Net Total Production - Mboe/d 141.50 - 143.50 FY 2026 Net Oil Production - Mbo/d 67.25 - 67.75 FY 2026 Net Total Production - Mboe/d 137.00 - 138.00 Unit Costs ($/boe) Depreciation, Depletion and Amortization $14.75 - $17.25 Cash G&A $0.70 - $0.90 Non-Cash Share-Based Compensation $0.10 - $0.20 Net Interest Expense $1.90 - $2.40 Production & Ad Valorem Taxes (% of Revenue) ~7% Cash Tax Rate(3) 27% - 30% Source: Company data and filings. Financial data as of 9/30/2026. Senior Notes Revolving Credit Facility (1) See Non-GAAP definitions and reconciliations in the appendix. (2) Gives effect to the 2026 Drop Down and McElroy Ranch Acquisition that closed in September 2026 and the Pending Buckhorn Acquisition expected to close in Q4 2026. (3) Percent of pre-tax income attributable to Viper Energy, Inc. (4) MRQA stands for Most Recent Quarter Annualized. Pro forma Net Debt / MRQA Adj. EBITDA estimated using Q3 ‘26 Adj. EBITDA / boe of $45.90 and ~3,200 boe/d of production from the Pending Buckhorn Acquisition. (5) Debt maturity profile as of 9/30/2026, pro-forma for the Pending Buckhorn Acquisition. Weighted Average Maturity of ~6.2 years 5.700% 4.900% 5.433%
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15 Appendix
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16 689 gross (19.0 net) horizontal wells(1) turned to production during Q3 ‘26 Near-term inventory of 38.9 net wells(1) currently in the process of active development and an additional 36.4 net line-of-sight wells(1) not currently being developed 104 gross rigs currently operating on Viper’s acreage, 11 of which are operated by Diamondback Portfolio Overview Source: Company data and estimates and Enverus. Acreage and activity data as of 9/30/2026. Existing permits or active development of Viper’s royalty acreage does not ensure that those wells will be turned to produc tion. (1) Wells normalized to 10,000’. (2) Work in progress wells represent those that have been spud and are expected to be turned to production within approximately t he next six to eight months. (3) Line-of-sight wells are those that are not currently in the process of active development, but for which Viper has reason to bel ieve that they will be turned to production within approximately the next 15 to 18 months. The expected timing of these wells is based primarily on permitting by third party operators or Diamondback’ s current expected completion schedule. Robust Work-In-Progress and Line-of-Sight Well Backlog Provides Visibility into Viper’s Production Outlook Diamondback Operated Third Party Operated Midland Delaware Midland Delaware Total Net Royalty Acres 31,291 5,809 29,321 31,677 98,098 Q3 '26 Gross Hz Wells(1) Turned to Production (Net 100% NRI Wells) 123 (11.6) 0 (0.0) 291 (5.0) 275 (2.4) 689 (19.0) Gross Producing Hz Locations(1) (Net 100% NRI Wells) 4,244 (268.5) 369 (22.4) 11,921 (190.0) 9,913 (144.1) 26,447 (625.0) Gross Active Rigs (Net 100% NRI Rigs) 11 (0.5) 0 (0.0) 39 (0.7) 54 (0.6) 104 (1.8) Gross Work-in-Progress(1)(2) (Net 100% NRI Wells) 303 (17.5) 0 (0.0) 768 (11.1) 894 (10.3) 1,965 (38.9) Gross (Net) Line-of-Sight(1)(3) 370 (22.5) 0 (0.0) 423 (7.8) 611 (6.1) 1,404 (36.4)
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17 Midland Basin Delaware Basin Net Royalty Acres ~31,000 ~5,800 Average NRI % 6.0% 5.2% Net DUCs / Permits ~40.0 - Delaware Basin Gross (Net) Locations Economic at $50 / Bbl(1) Midland Basin Gross (Net) Locations Economic at $50 / Bbl(1) Total Avg. Lateral MS / JM 835 (42) 11,000' LS 525 (28) 10,800' WCA 671 (38) 11,100' WCB 730 (41) 10,500' WCD 600 (36) 13,100' BRNT 224 (15) 11,700' Other(2) 631 (45) 10,600' Total 4,216 (245) 11,200' Diamondback Operated Inventory Over a Decade of Diamondback Operated Inventory Provides Long-Term Visibility into Sustained Production Source: Company data, filings and estimates. Note: locations and average lateral length based on internal company estimates a s of 12/31/2025. Totals may not sum due to rounding. (1) Defined as locations that can generate at least a 10% rate of return at $50/Bbl oil prices, $20/Bbl NGL prices and $3.00/Mcf gas prices. (2) Other zones comprised of Wolfcamp C, Upper Spraberry, Clearfork and Woodford intervals in the Midland Basin. (3) As of 9/30/2026. Diamondback Leasehold on Viper Royalty Acreage Total Avg. Lateral 2BS 238 (11) 10,700' 3BS 186 (8) 9,900' WCA 71 (3) 9,800' WCB 163 (9) 10,500' Total 658 (32) 10,300' Viper’s Diamondback Operated Royalty Acreage(3)
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18 Asset Statistics Current Hz. Rigs(1) Net Well Counts(2) Operator NRA Norm. Unit Count (3) Avg. NRI VNOM / Basin PDP DUCs / Permits 9,000 417 1.6% 17 / 23 78.7 8.8 2,785 44 5.3% 1 / 3 2.4 0.4 1,926 21 5.6% 6 / 6 8.0 4.9 1,860 72 2.0% 3 / 5 11.3 0.8 1,591 80 1.4% 1 / 2 14.3 0.9 1,532 71 1.7% 6 / 6 17.7 2.1 1,470 50 2.2% 0 / 6 13.5 0.2 All Others 9,156 471 1.7% 4 / 9 44.3 0.9 Total / Average: 29,321 1,227 1.9% 38 / 60 190.0 19.0 County NRA % Midland 5,029 17% Reagan 4,270 15% Martin 4,918 17% Howard 3,742 13% Glasscock 2,335 8% Upton 6,978 24% Other 2,049 7% Total NRA: 29,321 100% Midland Basin - Third-Party Operator Statistics Midland Basin Third-Party Acreage Overview Source: Company data, Enverus and filings. Totals may not sum due to rounding. (1) As of 10/14/2026. (2) As of 9/30/2026. Net Well Counts normalized to 10,000 lateral feet. (3) Normalized drilling and spacing units to one mile wide. Midland Basin - NRI Map
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19 County NRA % Reeves 14,771 46% Loving 4,002 13% Ward 3,845 12% Pecos 3,038 10% Lea 2,397 8% Eddy 2,133 7% Other 1,491 4% Total NRA: 31,677 100% Asset Statistics Current Hz. Rigs(1) Net Well Counts(2) Operator NRA Norm. Unit Count (3) Avg. NRI VNOM / Basin PDP DUCs / Permits 3,271 196 1.5% 7 / 11 10.2 1.3 3,213 143 2.2% 1 / 1 12.4 0.1 3,048 156 1.7% 3 / 11 13.1 0.7 2,527 185 1.2% 7 / 11 9.2 2.6 2,425 136 1.5% 4 / 15 10.6 0.7 2,297 89 2.3% 2 / 2 6.1 0.2 1,909 106 1.5% 0 / 4 8.6 0.1 1,171 76 1.4% 8 / 12 10.8 2.8 1,007 74 1.0% 2 / 11 6.5 1.3 All Others 10,809 643 1.6% 19 / 37 56.6 6.5 Total / Average: 31,677 1,804 1.6% 53 / 115 144.0 16.3 Delaware Basin Third-Party Acreage Overview Delaware Basin - Third-Party Operator Statistics Delaware Basin - NRI Map Source: Company data, Enverus and filings. Totals may not sum due to rounding. (1) As of 10/14/2026. (2) As of 9/30/2026. Net Well Counts normalized to 10,000 lateral feet. (3) Normalized drilling and spacing units to one mile wide.
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20 ~784,784 ~98,098 0 250,000 500,000 750,000 Viper Net Royalty Acres (Normalized to 1/8) Viper Net Royalty Acres How Viper Defines a “Net Royalty Acre” Source: Company data and filings. Acreage data as of 9/30/2026. Acreage Definition Comparison Viper’s Formula for Net Royalty Acreage Methodology for deriving “Net Royalty Acreage” differs widely across the industry Many companies calculate assuming there are eight royalty acres for every one net mineral acre (NMA) Viper derives its total net royalty acreage from net mineral ownership taking into consideration the royalty interest AND all other burdens Net Mineral Acres Lease Royalty and other burdens Net Royalty Acres NRA Example Assuming Standard ¼ Royalty 640-acre section 100% Mineral Interest Mineral Acres 640 NMA Mineral Acres 640 NMA Royalty Acres 160 NRA Royalty Acres 1,280 NRA Viper believes its methodology more accurately defines its acreage for which it will receive revenue
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21 Crude Oil (Bbls/day, $/Bbl) 4Q 2026 1Q 2027 2Q 2027 3Q 2027 4Q 2027 Deferred Premium Put Options - WTI 50,000 50,000 45,000 35,000 20,000 Strike $50.00 $50.00 $50.00 $50.00 $50.00 Premium ($1.32) ($1.36) ($1.35) ($1.35) ($1.32) Deferred Premium WTI-Brent Basis Put Options 30,000 -- -- -- -- Floor ($45.00) -- -- -- -- Premium ($1.48) -- -- -- -- Roll Swaps - WTI 15,000 -- -- -- -- Swap Price $3.97 -- -- -- -- Natural Gas - Henry Hub (Mmbtu/day, $/Mmbtu) 4Q 2026 1Q 2027 2Q 2027 3Q 2027 4Q 2027 Costless Collars - Henry Hub 60,000 -- -- -- -- Floor $2.75 -- -- -- -- Ceiling $6.64 -- -- -- -- Natural Gas Waha Basis (Mmbtu/day, $/Mmbtu) 4Q 2026 1Q 2027 2Q 2027 3Q 2027 4Q 2027 Swaps - Waha Basis 80,000 50,000 50,000 50,000 50,000 Swap Price ($1.74) ($1.40) ($1.40) ($1.40) ($1.40) Hedge Summary Source: Company data as of 10/30/2026. Given the Company’s Strong Balance Sheet, Viper’s Hedging Strategy is to Maximize Upside Exposure to Commodity Prices while Protecting Against the Extreme Downside
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22 Non-GAAP Definitions and Reconciliations Source: Company data and filings. Adjusted EBITDA: Viper defines Adjusted EBITDA as net income (loss) attributable to the Company, plus net income (loss) attributable to non-controlling interest (“net income (loss)”) before interest expense, net, non-cash share-based compensation expense, depreciation, depletion and amortization, impairment, non-cash (gain) loss on derivative instruments, provision for (benefit from) income taxes and other non-cash or non-recurring operating expenses. Adjusted EBITDA margin: Viper defines Adjusted EBITDA margin as Adjusted EBITDA divided by total operating income.
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23 Non-GAAP Definitions and Reconciliations Source: Company data and filings. Free Cash Flow: Viper defines Free Cash Flow as operating cash flow before working capital changes in excess of capital expenditures. Free Cash Flow margin: Viper defines Free Cash Flow margin as Free Cash Flow divided by total operating income. Net Debt: Viper defines the non-GAAP measure of net debt as debt (excluding debt issuance costs, discounts and premiums) less cash and cash equivalents.
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24 Viper Energy, Inc. 500 West Texas Ave., Suite 100 Midland, TX 79701 www.viperenergy.com Chip Seale (432) 247-6218 cseale@viperenergy.com