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2Q 2026 Earnings Conference Call & Webcast August 5 , 2026 www.talosenergy.com NYSE : TALO 280 122848088032038 201 080088 01028823801 00 82 8 2010 TALOS ENERGY SE SE
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2 Cautionary Statements Cautionary Statements The information in this communication includes “forward -looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Ac t”). All statements, other than statements of historical fact included in this communication regarding our strategy, future operations , financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward -looking statements. When used in this communication, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project ,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward- looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward- looking statements are based on our current beliefs, based on currently available information, as to the outcome and timing of future events. Fo rward-looking statements may include statements about: business strategy; estimated, potential or recoverable resources, reserves and produ ction; drilling prospects, inventories, projects and programs, including operating cost efficiencies, and non -operated assets; our ability to replace the reserves that we produce through drilling, acquisitions, recompletions or enhanced recovery; financial strategy, borrowing ba se under our bank credit facility, availability of financing sources, including project financing options, liquidity position and capital required for our development program, acquisitions and other capital expenditures; anticipated levels of stock repurchases and leverage ratio; realized oil and natural gas prices; changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements and the impact of such policies on us, our customers and suppliers, and the global economic environment; our ability to obtain financial assura nce instruments, including surety bonds, on commercially reasonable terms; expected collateral requirements under existing or fut ure acquisitions, surety agreements, hedging transactions, letters of credit and other secured debt; volatility in the political, legal and regulatory environments where we currently or in the future may operate; risks related to future mergers and acquisitions, including the risk we may not close when expected or at all, and may fail to realize the expected benefits of any such transaction; timing, restrictions an d amount of future production of oil, natural gas and NGLs, including changes in supply caused by OPEC or the war in Iran, and any related impact o n global oil prices, available resources, and domestic oil production; our hedging strategy and results; future drilling plans; availabili ty of pipeline connections and other infrastructure on economic terms; competition, government regulations, including financial assurance re quirements, and legislative and political developments; our ability to obtain permits and governmental approvals; pending legal, governme ntal or environmental matters; our marketing of oil, natural gas and NGLs; our integration of acquisitions and the anticipated post -acquisition performance of the Company; our ability to identify and acquire future leases, reserves, exploration projects and or business acquisitions on desired terms; costs of exploring, developing, acquiring or abandoning properties; general economic conditions, including the impact of continued inflation and associated changes in monetary policy; political and economic conditions and events in foreign oil, n atural gas and NGL producing countries and acts of terrorism or sabotage; credit markets and availability of financial instruments on reason able terms; estimates of future income taxes; our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities; our strategy with respect to our minority investment in the Zama asset; uncertainty regardi ng our future operating results and our future revenues and expenses; anticipated capital efficiency, margin enhancement and organizational improvements and additional cash flow; impact of new accounting pronouncements on earnings in future periods; and plans, obj ectives, expectations and intentions contained in this communication that are not historical. Additionally, forward -looking statements may include statements regarding pending acquisitions which are based on management’s current expectations and assumptions such as: futur e exploration and development opportunities; financing options; estimates of recoverable resources and resource potential; timi ng of final investment decisions; anticipated costs and expected production commencement and volumes; the timing, closing and benefits of the pending acquisitions; the anticipated impact on our financial position, growth opportunities and competitive position; and pr ojected prospects, plans and objectives related to these assets. All of the forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficul t to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility; global dem and for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies to set and maintain oil production leve ls and the impact of any such actions; foreign wars and conflicts, including the lack of a resolution to the war in Ukraine and ongoing hostilities in Israel and the Middle East, such as the war in Iran and their impact on commodity markets; the impact of any pandemic, and governmental measures related thereto; lack of necessary infrastructure, transportation and storage capacity as a result of oversupply, go vernment and regulations; political risks, including a global trade war or the impact of a prolonged federal government shutdown or lapse in federal appropriations that could disrupt our operations and future drilling plans and opportunities; lack of availability of drillin g and production equipment and services or skilled personnel; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats and incidents; elevated inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current di scoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes, including the impact of financial assurance requirements; changes in U.S. trade and labor policies, including the imposition of increased tariffs and resulting consequen ces; the uncertainty inherent in estimating reserves and in projecting future reservoir performance, recoverable resources, resource p otential and rates of production; cash flow and access to capital; the timing of development expenditures; risks to our industry and busin ess operations associated with legal challenges by non-governmental organizations and other groups; market factors impacting the availability o f surety bonds; and the other risks discussed in “Risk Factors” of our Annual Report on Form 10 -K for the year ended December 31, 2025 and our subsequent Quarterly Reports on Form 10-Qs, each as filed with the SEC. In addition, risks related to the pending acquisitions i nclude, but are not limited to, our ability to obtain regulatory approval and to consummate the acquisitions; our ability to realize the ant icipated benefits of our acquisitions; availability of future project financing; whether the parties elect to proceed with a FID and our abilit y to reach FID and/or production on the timeline currently contemplated or at all; risks associated with reliance on third -party operators; or risks relating to operations in foreign jurisdictions due to changes in applicable laws, regulations and policies affecting our projects. Should any risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this p resentation are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the st atements in this section, to reflect events or circumstances after the date of this presentation. Reserve Information Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions used by reserve engineers. In addition, the results of drilling, testing and production activities may justify re visions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any further product ion and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGL s that are ultimately recovered. We may use the terms "estimated resource potential," “gross reserves,” "estimated resource," "total recoverable resource potential" and "estimated ultimate recovery" or "EUR" which are not measures of "reserves" prepared in accordance with SEC guidelines or permitted to be included in SEC filings. These types of estimates do not represent, and are not intended to represent, any category of reserv es based on SEC definitions, are inherently by their nature more speculative than estimates of proved or other reserves prepared in accordanc e with SEC guidelines and do not constitute "reserves" within the meaning of the SEC's rules. These types of resource estimates are subj ect to greater uncertainties, and accordingly, are subject to a substantially greater risk of actually being realized. Investors are urged t o consider closely the disclosures and risk factors in the reports we file with the SEC. Production Estimates Estimates for future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, tran sportation, marketing and storage of oil and gas are subject to disruption due to infrastructure constraints, transportation, processing and storage availability, mechanical failure, human error, adverse weather conditions such as hurricanes, global political and macroecono mic events and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary signif icantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated. Use of Non-GAAP Financial Measures This presentation may include the use of various measures that have not been calculated in accordance with U.S. generally accept able accounting principles (GAAP) such as, but not limited to, EBITDA, Adjusted EBITDA, Adjusted EBITDA attributable to Talos Ener gy Inc., LTM Adjusted EBITDA attributable to Talos Energy Inc., Net Debt, Net Debt to LTM Adjusted EBITDA attributable to Talos Energy Inc., Adjusted Free Cash Flow attributable to Talos Energy Inc. and Leverage, Adjusted EBITDA attributable to Talos Energy Inc. excluding hedges, Adjusted Net Income (Loss) attributable to Talos Energy Inc. per diluted share, Adjusted Earnings Per Share, Cash Operating Expenses a nd Workovers, Adjusted General & Administrative Expense and PV-10. Non-GAAP financial measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Reconciliations for non -GAAP measure to GAAP measures are included in the appendix to this presentation and in the Company’s earnings release. Use of Projections This presentation may contain projections, such as, but not limited to, production volumes: cash expenses, including operating e xpenses, G&A and interest expense; capital expenditures; P&A and decommissioning expenditures; and collateral obligations. Our indepe ndent auditors have not audited, reviewed, compiled, or performed any procedures with respect to the projections for the purpose of their inclusion in this presentation, and accordingly, have not expressed an opinion or provided any other form of assurance with r espect thereto for the purpose of this presentation. These projections are for illustrative purposes only and should not be relied upon as b eing indicative of future results. The assumptions and estimates underlying the projected information are inherently uncertain and are subject t o a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially f rom those contained in the projected information. Even if our assumptions and estimates are correct, projections are inherently uncerta in due to a number of factors outside our control. Accordingly, there can be no assurance that the projected results are indicative of ou r future performance or that actual results will not differ materially from those presented in the projected information. Inclusion of the projected information in this presentation should not be regarded as a representation by any person that the results contained in the p rojected information will be achieved. Estimates for our future production volumes are based on assumptions of capital expenditure lev els and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated. Industry and Market Data This presentation has been prepared by us and includes market data and other statistical information from sources we believe to be reliable, including independent industry publications, governmental publications or other published independent sources. Some data is a lso based on our good faith estimates, which are derived from our review of internal sources as well as the independent sources describ ed above. Although we believe these sources are reliable, we have not independently verified the information and cannot guarantee its a ccuracy and completeness.
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3 Key Takeaways from 2Q 2026 Building the Foundation To Be a Leading Pure-Play Offshore E&P Strong Operational Execution and Performance Across the Base Business Three Strategic Pillars Anchored by Our Disciplined Capital Allocation Framework Improve Our Business Every Day Grow Production & Profitability Build a Long- Lived Scaled Portfolio Invest in projects that generate robust returns Return up to 50% of annual FCF to shareholders Strengthen targeting long-term leverage of 1.0x or lower Grow via selective accretive growth opportunities 3 2 1 Raised Full-Year 2026 Production Guidance for the Standalone Business Enhanced Financial Flexibility Supporting Strategy Execution Developing a Long-Lived Portfolio with Compelling Strategic Rationale Record Free Cash Flow Generation
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4 69 MBO/D Average Oil Production 94 MBOE/D Average Daily Production 73% Oil $402 MM Adj. EBITDA(1) $47/BOE Adj. EBITDA/BOE(1) $232 MM Adj. FCF(1)(2) (1) See “Non-GAAP Information” for details and reconciliations of GAAP to non-GAAP financial measures. Adj. EBITDA, Adj. EBITDA/BOE, Leverage, and Adj. FCF. (2) Adjusted Free Cash Flow is before changes in working capital. (3) Cash plus available Credit Facility capacity as of June 30, 2026. 2Q 2026 Key Takeaways Strong Execution and Momentum Across the Business in 1H 2026 2Q 2026 RESULTS OPTIMAL PERFORMANCE PLAN BALANCE SHEET 0.0 SIF Serious Injury or Fatality Share repurchases temporarily paused during acquisition blackout period Greater than 65% of 2026 Target Achieved $0 DRAWN Credit Facility 0.5x Leverage Ratio(1) ~$1.2 BN Liquidity(3) $578 MM Cash on Balance Sheet
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5 Expanding Deepwater Scale with Compelling Strategic Rationale (1) Based on 2Q 2026 Actuals; net to Talos. (2) Based on 2027 at flat $70/WTI and net purchase price of $475 MM; assumes estimated closing date of September 1, 2026. (3) Based on 2027 consensus EBITDA per Bloomberg; TALO 6/23/26 share price of $13.96, outstanding share count of 167 MM and net debt of $864 MM. (4) Based on 2027 consensus FCF per Bloomberg for standalone TALO and 2027 at flat $70/WTI for acquired assets. (5) Based on 2027 at flat $70/WTI. MEXICO UNITED STATES OF AMERCA HONDURAS Gulf of Mexico Gulf of America Caribbean Sea Gulf of America Bolt-On Adds 18 MBOE/D(1) and working interest in the greater Na Kika complex Offshore Mexico Development Farm-In Greenfield development with >200 MMBOE discovered gross recoverable resource Strategic Rationale • Gulf of America Bolt-On increases scale and grows oil production by ~20%(1) • Offshore Mexico greenfield development farm-in expands resource base in a proven deepwater basin • Offshore Honduras adds long-cycle exploration optionality in an underexplored basin at low entry cost • Non-Core Shelf Divestment improves oil-weighting and eliminates ~$54 MM of ARO • Transactions expected to extend resource life and further develop a long-lived, scaled portfolio Financial Rationale • Gulf of America transaction acquired at accretive 2027e EV/EBITDA of 1.8x(2) relative to TALO standalone 2027 consensus metrics of 2.7x(3) and is ~45% accretive to 2027 consensus free cash flow(4) • Remain committed to all 4 elements of capital allocation framework • Transactions funded through a combination of cash and new notes due 2034 • Expect pro-forma year-end 2027 leverage ratio <1.0x (5) • Expanded scale with minimal leverage increase is credit- positive Non-Core Shelf Divestment Non-operated, gas assets; eliminates ~$54 MM of ARO Offshore Honduras Block 80% operated position in offshore block spanning more than 4 million gross acres
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6 Gulf of America Mississippi Canyon Atwater Valley Gulf of America Shelf LOUISIANA (1) Based on 2Q 2026 Actuals; net to Talos. (2) Net to Talos. (3) Assumes estimated closing date of September 1, 2026.; taking into account the $42.5 MM deposit paid on 6/30, estimated cash at closing is expected to be $407.5 MM to $457.5MM. (4) Based on NSAI SEC YE2025 Reserves report; net to Talos and net of P&A. (5) 50% upside sharing subject to commodity-price-based thresholds if realized price exceeds $60/BBL. Gulf of America Bolt-On Acquisition Growing Production and Profitability Through Expanded Deepwater Scale Transaction Summary Transaction Details • Talos and Ridgewood Energy to jointly acquire Shell’s interest in the greater Na Kika complex • $850 MM purchase price (2) based on 7/1/25 effective date; final purchase price(2) expected to be $450 MM to $500 MM(3) • Expected to close in 3Q 2026 Acquired Assets • Includes Shell’s interest in the operated Coulomb field, 4 non-operated fields and ullage in the Na Kika platform • 2Q 2026 Production of 18 MBOE/D; 76% oil • Proved Reserves of 23 MMBOE (4); Probable Reserves of 10 MMBOE(4) Other Considerations • BP waived preferential right • Upside sharing agreement (5) with seller from closing to year-end 2027 2Q 2026 Key Metrics Talos GoA Bolt-On Pro-Forma Production, MBO/D 69 13 82 Production, MBOE/D 94 18 111 % Oil 73% 76% 74% LOE $/BOE ~$18 ~$5 ~$16 EBITDA Margins $/BOE ~$47 ~$77 ~$52 Talos Acreage Acquired Acreage Acreage Position Na Kika Platform FOURIER (Op) BP: 50% Talos: 25% COULOMB (Op) Talos: 50% HERSCHEL (Op) BP: 50% Talos: 25% ARIEL (Op) BP: 50% Talos: 25% KEPLER (Op) BP: 50% Talos: 25% ISABELA (Op) BP: 100% GALAPAGOS & CPN Strategic Rationale • Accretive bolt-on with attractive returns; grows oil production by ~20%(1) • Identified material Infrastructure-Led Exploration (ILX) opportunities • Leverages differentiated track record of field life extension; unlocking upside beyond current reserves • Expect operated Coulomb development opportunity to compete for capital in 2027
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7 Offshore Mexico Development Farm-In Transaction Expanding Resource Base in a Proven Basin Through Material Greenfield Development With Exploration Upside Transaction Summary Transaction Details • Talos to farm-in to Repsol operated Block 29 with a 50% WI; Talos and Repsol are the sole partners • No upfront cash consideration; limited capital spend in 2026 • FID payment of $30 MM, carry on one planned exploration well capped at $20 MM and reimbursement of certain pre-closing costs Acquired Assets • Located in proven Salinas-Sureste Basin in the southern Gulf of Mexico • Block 29 contains two Miocene oil discoveries, Polok and Chinwol containing net oil columns of more than 200 and 150 meters, respectively Other Considerations • SENER approval required to close • Expect to progress toward FID in 2027 (1) Partial Block 29 acreage release expected to occur once approved. Strategic Rationale • Greenfield development anchored by existing discoveries >200 MMBOE gross recoverable resource featuring FPSO development concept • First infrastructure in the area, positioned to potentially host nearby discoveries • Attractive exploration upside of an additional ~200 MMBOE of estimated on-block gross resource potential Acreage Position(1) Gulf of Mexico MEXICO Block 7 Block 9 Block 29 Block 10 CHINWOL POLOK ZAMA Xaxamani Xale Kan Yatzil Sayulita Sáasil Cholula Naajal Yoti Este Yopaat Sáasken Talos Acreage Acquired Acreage On-Block Discovery Off-Block Discovery Exploration Prospect
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8 Offshore Honduras Building Portfolio Longevity Through Large Scale Exploration Potential at Low Entry Cost Strategic Rationale • Provides exploration exposure to an underexplored offshore basin with large resource potential at a low entry cost • Existing on-block Main Cape oil discovery validates working petroleum system and provides appraisal upside • Initial 3D seismic campaign planned for 2H 2026 • Optionality to bring in strategic partners via farm-down Acreage Position Caribbean Sea Gulf of America Pacific Ocean MEXICO U.S.A. MAIN CAPE HONDURAS Acquired Acreage On-Block Discovery Transaction Summary Transaction Details • Talos to acquire an 80% WI and become operator; CaribX to retain 20% WI • Seismic commitment and minimal sunk cost reimbursement (as part of the approved initial phase of the contract) • Option to drill exploration well contingent on seismic results (as part of the approved initial phase of the contract) Acquired Assets • Located in the Patuca and Main Cape Basins; spanning both shallow and deepwater • Block size is more than 4 million gross acres and equivalent to ~700 Gulf of America blocks Other Considerations • Closed on 45% WI and operatorship • Acquisition of remaining 35% WI is subject to Secretaría de Energía (SEN); expected within approximately 90 days
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9 Return of Capital Framework Unchanged Share Count Reduced by ~7% Under Framework; No 2Q 2026 Repurchases Due to Acquisition-related Blackout $135 2Q 2025 3Q 2025 4Q 2025 1Q 2026 2Q 2026 Cumulative Value of Shares Repurchased $ Millions • Returned $135 MM to shareholders since announcing return of capital framework in 2Q 2025 • Outstanding share count reduced by ~7% since 2Q 2025 • Share repurchase authorization recently increased back up to $200 MM 167 2Q 2025 3Q 2025 4Q 2025 1Q 2026 2Q 2026 Total Shares Outstanding MM shares
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10 (1) Cash plus available Credit Facility capacity as of June 30, 2026; Excludes upsized credit facility effective upon closing of the Gulf of America bolt-on acquisition. (2) See “Non-GAAP Information” for details and reconciliations of GAAP to non-GAAP financial measures. (3) Availability reflects $96 MM of letters of credit. Enhanced Financial Flexibility Underpins Strategic Priorities Upsized Credit Facility Strengthens Liquidity; No Debt Maturities Through 2030 Credit Facility $604(3) $0 $0 $0 $625 $0 $0 $800 Cash $578 Liquidity 2Q 2026 2026 2027 2028 2029 2030 2031 2032 2033 2034 Outstanding Debt Maturities $ Millions $0 Drawn Credit Facility $578 MM Cash on Balance Sheet(1) ~$1.2 BN Liquidity(1) 0.5x Leverage Ratio(2) $0 DRAWN Refinanced 9% 2029 notes with $800 MM of new 8% 8-year notes
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11 Advantaged Cost Structure + Top Decile EBITDA Margin in E&P Sector (1) Source: Expense and production data is Gulf of America only; peers include KOS, MUR and WTI. Based on company SEC filings. (2) See "Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures. Source: FactSet as of July 13, 2026. Comparable group includes 27 U.S. listed E&P companies with market capitalization of over $1 BN. $16.70 $15.83 $16.14 $18.25 2024 2025 1Q 2026 2Q 2026 Optimal Performance Plan Translating Into Operating Cost Efficiencies Operating Expenses $/BOE $10 $15 $20 $25 2023 2024 2025 1Q 2026 Advantaged Cost Structure vs Gulf of America E&P Peers(1) Operating Expenses $/BOE $38.44 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 2026E EBITDA Margin Consensus $/BOE Talos TOP DECILE Top Decile EBITDA/BOE Margin in the E&P sector(2) Peer E&P Avg. $17.54 Talos $16.14 $1.75/BOE Workover Exp.
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12 Updated 2026 Operational and Financial Outlook (1) Excludes acquisitions; (2) Includes Lease Operating Expenses and Maintenance; (3) Includes insurance costs; (4) Includes reimbursements under production handling agreements; (5) Excludes non-cash equity- based compensation and transaction and other expenses; (6) Includes cash interest expense on debt and finance lease, surety charges and amortization of deferred financing costs and original issue discounts. * Due to the forward-looking nature a reconciliation of Cash Operating Expenses and G&A to the most directly comparable GAAP measure could not be reconciled without unreasonable efforts. 2026 Production Guidance Considerations • Annual downtime assumptions include: ‒ 6 MBOE/D of Planned Downtime • Includes 2 MBOE/D related to Genovesa; well returned to production in late 2Q 2026 ‒ 4 MBOE/D of Weather and Other Unplanned Downtime • 3Q 2026 production guidance 61 – 65 MBO/D and 81 – 85 MBOE/D • 3Q and full-year 2026 guidance: ‒ Excludes the previously announced Gulf of America acquisition ‒ Includes the impact of the closed non-core shelf divestment; 2Q 2026 production was approximately 700 BO/D / 3.5 MBOE/D (~20% oil) • Updated guidance will be provided following the expected closing of the acquisition in 3Q 2026 Original Guidance ($ Millions, unless highlighted) Revised 2026E Guidance ($ Millions, unless highlighted) Production Avg. Daily Production (MBOE/D) 85 – 90 87 – 91 Avg. Daily Oil Production (MBO/D) 62 – 66 64 – 68 CAPEX Capital Expenditures(1) $500 – $550 Unchanged P&A Expenditures P&A, Decommissioning $100 – $130 Unchanged Cash Expenses Cash Operating Expenses and Workovers(2)(3)(4)* $560 – $590 Unchanged G&A(3)(5)* $130 – $140 $135 – $145 Interest Expense(6) $155 – $165 Unchanged 2026 Oil Production (MBO/D) Increased Guidance Driven by Base Performance Despite Divestment Impact Original Guidance Base Performance Shelf Divestment Revised Guidance +2% +3% 64 midpoint 66 midpoint
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13 Focused 2026 Development, Exploration and Appraisal Activity Balanced Investment Across Infrastructure-Led Development, Exploration and Appraisal, and Monument 2 4 3 1 5 6 Cardona – Operated • Host Facility: Pompano • Spud Date: 4Q 2025 • First Oil Date: January 2026 CPN – Operated • Host Facility: Na Kika • Spud Date: 1Q 2026 • First Oil Date: 3Q 2026 Brutus Program – Operated • Host Facility: Brutus • Spud Date: 3Q 2026 • First Oil Date: 2H 2026 Development Activity 1 2 3 4 Exploration and Appraisal Activity Daenerys – Operated • Host Facility: TBD • Spud Date: 2Q 2026 • Appraisal Results: Late 2026 5 Key Workover Activity Genovesa – Operated • Host Facility: Na Kika • Planned Activity: 2Q 2026 • Return to Production: June 2026 6 Talos Acreage Talos Seismic First Oil Expected in 3Q 2026 First Oil Achieved First Well Drilled; ~250 ft of net pay Monument – Non-Op • Host Facility: Shenandoah • Spud Date: Drilling Underway • First Oil Date: Year-End 2026 Returned to production in June Appraisal Well Spud NEW NEW NEW
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14 Talos Investment Rationale DELIVERING on Our Commitments Strong Financial and Operational Performance • High margin oil weighted production • Industry leading low-cost deepwater operator Committed to Balance Sheet Strength • Disciplined capital allocation framework • Target long-term leverage of 1.0x or lower Leading Pure-Play Offshore E&P Company • Expertise in drilling, engineering, subsea completion and exploration • Drive operational excellence to generate FCF Returning Capital to Shareholders • Return up to 50% of annual FCF • Prioritize share repurchases as shareholder return framework Disciplined Exploration • Strategic focus to lengthen the portfolio and grow the business • Balance between material opportunities and infrastructure-led
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15 Appendix
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16 (1) Based on gross 2-stream production data. (2) Based on Welligence production data for Gulf of America; cum liquids production for Jan. 2025 to January 2026. Peers in Top 10 include BP, Chevro n, OXY and Shell. Katmai Field Production Expected To Remain Flat Through 2027 Advancing Multiple Prospects in the Greater Katmai Area for Future Development Recent Highlights • Katmai West #2 first oil achieved in June 2025 • Tarantula recently hit sustained output of ~38 MBOE/D through incremental debottlenecking efforts • Katmai Field production is expected to remain flat through late 2027 Future Development Options • Added additional inventory in the greater Katmai area, leveraging newly reprocessed data at the December 2025 lease sale • Maturing multiple prospects, including Katmai North, for future development in the greater Katmai area • Leveraging state-of-the-art seismic and proprietary reprocessing to advance prospects to drill-ready status • Significant future facility expansion possible with material success Tarantula Facility 0 10,000 20,000 30,000 40,000 2Q24 3Q24 4Q24 1Q25 2Q25 3Q25 4Q25 2026e 2027e BOE/D Katmai Field Production(1) Facility Expansion Katmai West #2 First Oil Tarantula Capacity Debottlenecking 0 2 4 6 8 10 Peer Peer Peer Peer Peer Peer Peer Katmai West #1 Peer Peer Cum Liquids MMBBLs Katmai West #1 Ranks in Top 10 Wells in the Gulf of America(2) Locator Map Katmai Field Tarantula Facility Katmai North Prospect Facility Prospect Field Talos-Awarded Block Talos Acreage Talos Seismic
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17 Scale + Inventory Growth • Portfolio spans multiple play types across the Gulf of America • Rapidly expanding Wilcox portfolio • Advantaged position in the prolific Katmai Basin Disciplined Exploration • Focus on material opportunities in subsalt Miocene and Wilcox • Supplement with lower-risk, amplitude supported prospects • High rates of return with short cycle times Lease Sale Momentum • Awarded all 11 leases from the December 2025 lease sale • Added 300+ MMBOE operated prospective gross unrisked resource • Expanded Wilcox and Katmai inventory Leveraging Modern Technology • Investing in state-of-the-art seismic and proprietary reprocessing • Broad multi-client seismic footprint across the Gulf of America • Modern imaging de-risks prospects and improves success rates Exploration Strategy and Portfolio Update Strategic Focus To Lengthen the Portfolio and Grow the Business 0 2 4 6 0 1 2 3 4 Number of Prospects Lease Sale Prospects by Play Type Sized by Resource Potential Amplitude Subsalt Miocene Wilcox Talos Acreage Talos Seismic Talos-Awarded Block Katmai Neptune Daenerys
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18 Daenerys – Subsalt Miocene Discovery Commenced Appraisal Well Program; Results from First Appraisal Well Expected by Year-End 2026 Discovery Well Highlights • Large Miocene structure • Discovery well drilled to total vertical depth of 33,228 ft • Drilled 12 days ahead of schedule and ~$16 MM under budget • Encountered oil pay in multiple high- quality, sub-salt Miocene sands; confirms presence of oil and validates geologic and geophysical models • Discovery well has been temporarily suspended to preserve future utility Appraisal Well Objectives • Test the northern part of the prospect • Well planned to penetrate multiple prospective intervals • Assess reservoir and fluid properties • Well designed to allow multiple future sidetracks for further appraisal and/or production Appraisal well spud with results expected by year-end 2026. Working Interest • Talos – 27% (Operator) • Shell Offshore Inc. – 22.5% • Red Willow – 22.5% • Houston Energy, L.P. – 10% • HEQ II Daenerys, LLC – 9% • Cathexis – 9% SALT SALT Discovery Well Projected Appraisal Well TBD
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19 Monument #3 Well Monument #4 Well Discovery Well WR 272 #1 Discovery Well WR 271 #1 Prospective Drilling Location 2P Reserves Operational Update • Drilled Monument #3 to TD finding ~250 ft of net TVT oil pay which is in line with pre-drill expectations • Rig operations at the Monument field will continue with the drilling of the second Monument development well followed by completion operations at the two wells • First oil at the Wilcox development is expected by year-end 2026 Background • Wilcox oil discovery announced in 2020, FID February 2024; good seismic image, faulted 4-way closure at ~30,500' • 17-mile tieback to new Shenandoah Facility via PHA; committed firm capacity of 20 MBBL/D • Prospective drilling location provides compelling upside over base development case • Talos increased its working interest to 29.76% from 21.4% in March 2025 • Beacon – 41.67% (Operator) • Talos – 29.76% • Navitas Petroleum – 28.57% Note: Depictions of future wells are notional. (1) Does not include the Prospective Drilling Location fault block. (2) 2P includes proved and probable reserves estimated by Netherland, Sewell & Associates, Inc. (‘NSAI”) as of December 31, 2025. Monument – Subsalt Wilcox Development Underway Finished Drilling Operations at Monument #3 Well; First Oil Expected by Year-End 2026 Wilcox Structure MapStrategic Elements Est. 2P Reserves (Gross MMBOE)(1)(2) First Oil Est. Initial Rate (Gross MBOE/D) Percent Oil Target Depth (Feet TVDSS) Host Facility ~115 MMBOE Year-end 2026 ~20 - 30 ~91% 30,500 ft Shenandoah Monument #3 ~250 ft TVT Net Pay WR 272 #1 ~232 ft TVT Net Pay Key Data Points South Fault Block Logs Monument #3 Well Miocene Oligocene Wilcox Cretaceous SALT Monument #4 Well Shenandoah
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20 Non-GAAP Reconciliations (1) Other income (expense) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2026, it includes a $14.3 MM litigation settlement accrued as an expense offset by a $6.8 MM gain on the Incremental Mexico Equity Sale. For the three months ended September 30, 2025, it includes the derecognition of $8.9 MM related to a deferred payment that was deemed uncollectible. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency and are included in “Other operating (income) expense” on our consolidated statements of operations. (3) The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA attributable to Talos Energy Inc. on an unrealized basis during the period the derivatives settled. (4) One Boe is equal to six MCF of natural gas or one BBL of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. Three Months Ended ($ Thousands) June 30, 2026 March 31, 2026 December 31, 2025 September 30, 2025 Reconciliation of Net Income (Loss) attributable to Talos Energy Inc. to Adjusted EBITDA attributable to Talos Energy Inc.: Net Income (loss) attributable to Talos Energy Inc. $149,667 $(256,165) $(202,580) $(95,905) Net income (loss) attributable to noncontrolling interest $222 $161 $(1,031) $(3) Net Income (loss) $149,889 $(256,004) $(203,611) $(95,908) Interest expense $39,162 $39,178 $40,796 $40,847 Income tax expense (benefit) $44,837 $(65,292) $(48,448) $(24,204) Depreciation, depletion and amortization $229,369 $230,384 $243,222 $262,637 Accretion expense $35,908 $34,939 $31,592 $30,764 EBITDA $499,165 $(16,795) $63,551 $214,136 Impairment of oil and natural gas properties — $145,018 $170,392 $60,209 Transaction and other (income) expenses(1) $1,344 $8,605 $1,100 $9,253 Decommissioning obligations(2) $215 $162 $3,010 $316 Derivative fair value (gain) loss(3) $(30,549) $173,547 $(30,227) $(4,226) Net cash received (paid) on settled derivative instruments(3) $(74,146) $(22,470) $26,384 $16,605 Non-cash equity-based compensation expense $6,409 $5,336 $4,919 $4,955 Adjusted EBITDA $402,438 $293,403 $239,129 $301,248 Less: adjustment for noncontrolling interest $258 $196 $(1,001) $8 Adjusted EBITDA attributable to Talos Energy Inc. $402,180 $293,207 $240,130 $301,240 Add: Net cash (received) paid on settled derivative instruments(3) $74,146 $22,470 $(26,384) $(16,605) Adjusted EBITDA attributable to Talos Energy Inc. excluding hedges $476,326 $315,677 $213,746 $284,635 Production: BOE(4) 8,529 7,994 8,203 8,757 Adjusted EBITDA attributable to Talos Energy Inc. and Adjusted EBITDA attributable to Talos Energy Inc. excluding hedges margin: Adjusted EBITDA attributable to Talos Energy Inc. per BOE(4) $47.15 $36.68 $29.27 $34.40 Adjusted EBITDA attributable to Talos Energy Inc. excluding hedges per BOE(1)(4) $55.85 $39.49 $26.06 $32.50
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21 Non-GAAP Reconciliations (1) Includes settlement of asset retirement obligations. (2) Includes accruals and excludes acquisitions. (3) Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. (4) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. Three Months Ended ($ Thousands) June 30, 2026 Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow attributable to Talos Energy Inc. (bef ore changes in working capital): Net cash provided by operating activities(1) $300,636 (Increase) decrease in operating assets and liabilities $1,121 Capital expenditures(2) $(112,518) Decommissioning obligations settled $(221) Transaction and other (income) expenses(3) $1,344 Decommissioning obligations(4) $215 Amortization of deferred financing costs and original issue discount $(1,896) Income tax benefit $44,837 Adjustment for noncontrolling interest $(258) Other adjustments $(1,683) Adjusted Free Cash Flow attributable to Talos Energy Inc. (before changes in working capital) $231,577 Three Months Ended ($ Thousands) June 30, 2026 Reconciliation of Adjusted EBITDA attributable to Talos Energy Inc. to Adjusted Free Cash Flow attributable to Talos Energy Inc. (before changes in working capital): Adjusted EBITDA attributable to Talos Energy Inc. $402,180 Capital expenditures $(112,518) Plugging & abandonment $(18,702) Decommissioning obligations settled $(221) Interest expense $(39,162) Adjusted Free Cash Flow attributable to Talos Energy Inc. (before changes in working capital) $231,577
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22 Non-GAAP Reconciliations Three Months Ended ($ Thousands) June 30, 2026 Reconciliation of General & Administrative Expenses to Adjusted General & Administrative Expenses: Total General and administrative expense $44,626 Transaction expenses $(1,344) Non-cash equity-based compensation expense $(6,409) Adjusted General & Administrative Expenses $36,873
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23 Non-GAAP Reconciliations (1) Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. (3) The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) attributable to Talos Energy Inc. on an unrealized basis during the period the derivatives settled. (4) The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding. Three Months Ended, June 30, 2026 ($ Thousands, except per share amounts) Basic per Share Diluted per Share Reconciliation of Net Income (Loss) attributable to Talos Energy Inc. to Adjusted Net Income (Loss) attributable to Talos Energy Inc.: Net Income (loss) attributable to Talos Energy Inc. $149,667 $0.90 $0.88 Transaction and other (income) expenses(1) $1,344 $0.01 $0.01 Decommissioning obligations(2) $215 $0.00 $0.00 Derivative fair value (gain) loss(3) $(30,549) $(0.18) $(0.18) Net cash received (paid) on settled derivative instruments(3) $(74,146) $(0.44) $(0.44) Non-cash income tax benefit $44,837 $0.27 $0.26 Non-cash equity-based compensation expense $6,409 $0.04 $0.04 Adjusted Net Income (Loss)(4) attributable to Talos Energy Inc. $97,777 $0.59 $0.57 Weighted average common shares outstanding at June 30, 2026: Basic 166,980 Diluted 170,085
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24 Non-GAAP Reconciliations (1) Net Debt / LTM Adjusted EBITDA attributable to Talos Energy Inc. figure excludes the payments of Finance Lease. Had the Finance Lease been included, Net Debt / LTM Adjusted EBITDA attributable to Talos Energy Inc. would have been 0.6x. ($ Thousands) June 30, 2026 Reconciliation of Net Debt: 9.000% Second-Priority Senior Secured Notes $625,000 9.375% Second-Priority Senior Secured Notes $625,000 Bank Credit Facility – matures January 2030 — Total Debt $1,250,000 Less: Cash and cash equivalents $(577,587) Net Debt $672,413 Calculation of LTM Adjusted EBITDA attributable to Talos Energy Inc.: Adjusted EBITDA attributable to Talos Energy Inc. for three months period ended September 30, 2025 $301,240 Adjusted EBITDA attributable to Talos Energy Inc. for three months period ended December 31, 2025 $240,130 Adjusted EBITDA attributable to Talos Energy Inc. for three months period ended March 31, 2026 $293,207 Adjusted EBITDA attributable to Talos Energy Inc. for three months period ended June 30, 2026 $402,180 LTM Adjusted EBITDA attributable to Talos Energy Inc. $1,236,757 Reconciliation of Net Debt to LTM Adjusted EBITDA attributable to Talos Energy Inc.: Net Debt / LTM Adjusted EBITDA attributable to Talos Energy Inc.(1) 0.5x
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25 Talos Hedge Book as of July 31, 2026 This reflects volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of July 31, 2026. Instrument Type Avg. Daily Volume W.A. Swap W.A. Floor W.A. Ceiling Crude – WTI (BBLs) (Per BBL) (Per BBL) (Per BBL) July – September 2026 Fixed Swaps 3,685 $67.77 — — Collar 21,000 — $61.67 $74.80 October – December 2026 Fixed Swaps 4,000 $62.50 — — Collar 22,978 — $61.52 $73.81 January – March 2027 Fixed Swaps 7,000 $73.27 — — Collar 22,000 — $60.91 $75.58 April – June 2027 Fixed Swaps 7,000 $73.27 — — Collar 14,000 — $65.36 $77.93 Natural Gas – HH NYMEX (MMBTU) (Per MMBTU) (Per MMBTU) (Per MMBTU) July – September 2026 Fixed Swaps 26,739 $3.48 — — Collar 6,631 — $2.75 $3.71 October – December 2026 Fixed Swaps 29,946 $3.78 — — Collar 10,000 — $2.75 $3.71 January – March 2027 Collar 45,000 — $3.39 $4.70 April – June 2027 Collar 10,000 — $3.00 $3.67
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26 www.talosenergy.com NYSE: TALO