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1 3Q 2026 Earnings Conference Call & Webcast November 4, 2026 www.talosenergy.com NYSE: TALO
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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 the timing, expected first oil, and anticipated operating cost effic iencies related thereto; prospects, projects and activities related to our non-operated assets over which we have less control; 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, anticipated leverage ratio, availability of financing sources, including project financing options, liq uidity position and capital required for our exploration and development program, acquisitions and other capital expenditures; anticipated levels of stock repurchases; realized oil and natural gas prices; changes in tariffs, trade barriers, price and exchange controls and other r egulatory requirements and the impact of such policies on us, our customers and suppliers, and the global economic environment; our abi lity to obtain financial assurance instruments, including surety bonds, on commercially reasonable terms; expected collateral requirements u nder existing or future 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, in cluding the risk we may not close when expected or at all, and may fail to realize the expected benefits of any such transaction; timing, rest rictions and 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 on global oil prices, available resources, and domestic oil production; our hedging strategy and results; future drill ing plans; availability of pipeline connections and other infrastructure on economic terms; competition, government regulations, includi ng financial assurance requirements, and legislative and political developments; our ability to obtain permits and governmental approvals; pending legal, governmental or environmental matters; our marketing of oil, natural gas and NGLs; our integration of acquisitions, cost savi ngs related thereto, and the anticipated post-acquisition performance of the assets and the Company; our ability to identify, acquire or dev elop future acquired assets, leases, reserves, exploration projects and or business acquisitions on desired terms; estimated costs of exp loring, developing, acquiring or abandoning properties; estimated EBITDA margins; operational and financial guidance; the timing of f irst oil; seismic results; general economic conditions, including the impact of continued inflation and associated changes in monetary policy; political and economic conditions and events in foreign oil, natural gas and NGL producing countries and acts of terrorism or sabotage; credit markets and availability of financial instruments on reasonable 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 strateg y with respect to our minority investment in the Zama asset; uncertainty regarding our future operating results and our future revenues and expense s; anticipated capital efficiency, margin enhancement and organizational improvements and additional cash flow; impact of new accounting pronouncements on earnings in future periods; and plans, objectives, expectations and intentions contained in this communicat ion that are not historical. Additionally, forward-looking statements may include statements regarding pending acquisitions and new leases wh ich are based on management’s current expectations and assumptions such as: future exploration and development opportunities; financi ng options; estimates of recoverable resources and resource potential; timing of final investment decisions; anticipated costs a nd 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 projected prospects, plans and objectives related to t hese assets. All of the forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and ma ny 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 ongoing military operations and hostilities in the Middle E ast and the resulting impact on commodity markets; the impact of any pandemic, and governmental measures related thereto; lack of necessa ry infrastructure, transportation and storage capacity as a result of oversupply, government and regulations; political risks, i ncluding 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 drilling and production equipment and services or skille d personnel; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats and inc idents; elevated inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain ac cess to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; d rilling and other operating risks; well control risk; regulatory changes, including the impact of financial assurance requirements; chang es in U.S. trade and labor policies, including the imposition of increased tariffs and resulting consequences; the uncertainty inherent in est imating reserves and in projecting future reservoir performance, recoverable resources, resource potential and rates of production; cash flow and access to capital; the timing of development expenditures; risks to our industry and business operations associated with legal challeng es by non- governmental organizations and other groups; market factors impacting the availability of surety bonds; and the other risks d iscussed 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 include, but are not limited to, our ability to obtain regulatory approval and to consummate the acquisitions; our ability to realize the anticipated benefits of our acquisitions; availability of future project financing; whether the parties elect to proceed with a FID and our ability to reach FID and/or production on t he 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 i n 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 statements 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 prod uction 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 various terms such as "estimated gross resource potential," “gross reserves,” "estimated resource," "gross recoverable resource" "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 acc eptable 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 operatin g expenses, G&A and interest expense; capital expenditures; P&A and decommissioning expenditures; and collateral obligations. Our independent 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 materiall y from 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 described 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 3Q 2026 Building the Foundation To Be a Leading Pure-Play Offshore E&P Consistent Execution by 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 Completed Gulf of America Bolt-On Acquisition Advancing a Deeper Portfolio of Development and Exploration Opportunities Raised 2026 Full-Year Production Guidance Strong Financial Performance Supported by Premium Oil Realizations
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4 69 MBO/D Average Oil Production 92 MBOE/D Average Daily Production 75% Oil $406 MM Adj. EBITDA(1) $52/BOE Adj. EBITDA/BOE(1) $186 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 September 30, 2026. 3Q 2026 Key Takeaways Consistent Execution Delivering Strong Operational and Financial Performance 3Q 2026 RESULTS OPTIMAL PERFORMANCE PLAN BALANCE SHEET 0.0 SIF Serious Injury or Fatality $24 MM Returned to Shareholders Greater than 100% of 2026 Target Achieved $0 DRAWN Credit Facility 0.6x Leverage Ratio(1) ~$1.1 BN Liquidity(3) $410 MM Cash on Balance Sheet
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5(1) Based on 2027 at flat $70/WTI. Developing a Long-Lived, Scaled Portfolio with Enhanced Financial Flexibility Completed Gulf of America Transactions While Advancing Block 29 and Offshore Honduras MEXICO HONDURAS Gulf of Mexico Gulf of America Caribbean Sea UNITED STATES OF AMERICA Gulf of America Bolt-On Completed in 3Q 2026 Offshore Mexico Farm-In Advancing toward FID in 2027 Strategic Rationale • Increased deepwater scale across the Gulf of America, Offshore Mexico and Offshore Honduras • Deeper development portfolio spanning the offshore lifecycle • Expanded exploration opportunities across three offshore basins • Extended resource life supports a durable, scaled offshore portfolio Financial Rationale • Enhanced financial flexibility while increasing deepwater scale • Disciplined capital allocation framework underpins the strategy • Year-end 2027 leverage ratio expected <1.0x(1) • Strong balance sheet and liquidity support continued investment and execution of the long-term strategy Non-Core Shelf Divestment Completed in 3Q 2026 Offshore Honduras Block Commenced 3D Seismic Program
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6 Proven Track Record of Unlocking Significant Reserve Upside Recent Gulf of America Acquisition Adds Development Opportunities to Drive Further Value Creation 2P Reserves at time of Acquisitions Year-End 2025 Delivering Value Beyond Acquired Reserves Ram Powell, Pompano and Brutus Assets MMBOE Production Since Acquisitions 2P Reserves Track record of unlocking upside beyond acquired reserves and extending field life. $420 MM Final Net Cash Purchase Price COMPLETED BOLT-ON ACQUISITION Expect operated Coulomb development opportunity to compete for capital in 2027. > 40% Uplift
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7 Acreage Position Block 29 Block 7 Block 9 Block 10 Yatzil Sayulita Sáasil Cholula Naajal Yoti Este Yopaat Sáasken Xale Kan CHINWOL POLOK ZAMA DEVELOPMENT AREA Exploration Acreage Development Area On-Block Discovery Off-Block Discovery Exploration Prospect Advancing Deepwater Exploration and Development Opportunities Progressing Block 29 Toward FID; Offshore Honduras Deepwater 3D Seismic Campaign Underway Offshore Honduras Strategic Rationale and Summary • More than 4 million gross acres; equivalent to ~700 Gulf of America blocks • Provides exploration exposure to an underexplored offshore basin with large resource potential at a low entry cost • Existing Main Cape oil discovery validates working petroleum system and provides appraisal upside • Deepwater 3D seismic campaign commenced in October, less than three months after signing Acreage Position Acquired Acreage On-Block Discovery MAIN CAPE HONDURAS Block 29 Strategic Rationale and Summary • Greenfield development anchored by existing discoveries with >200 MMBOE of gross recoverable resource • Attractive exploration upside with an additional ~200 MMBOE of estimated on-block gross resource potential • Two Miocene oil discoveries, Polok and Chinwol, underpin the FPSO development concept • Progressing SENER approval required to close farm-in transaction • Expect to advance the development toward FID in 2027 • Exploration well planned for late 2027
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8 Return of Capital Framework Unchanged Resumed Share Repurchases in 3Q; Returned ~$62 MM to Shareholders YTD $159 2Q 2025 3Q 2025 4Q 2025 1Q 2026 2Q 2026 3Q 2026 Cumulative Value of Shares Repurchased $ Millions • Returned ~$160 MM to shareholders since announcing return of capital framework in 2Q 2025 • Outstanding share count reduced by ~8% since 2Q 2025 • Remaining share repurchase authorization of $176 MM 175 166 2Q 2025 3Q 2025 4Q 2025 1Q 2026 2Q 2026 3Q 2026 Total Shares Outstanding MM shares
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9 (1) Cash plus available Credit Facility capacity as of September 30, 2026. (2) See “Non-GAAP Information” for details and reconciliations of GAAP to non-GAAP financial measures. (3) Availability reflects $184 MM of letters of credit. Enhanced Financial Flexibility Underpins Strategic Priorities No Debt Maturities Until Next Decade; Upsized Credit Facility Supports Strong Liquidity Credit Facility $665(3) $0 $0 $0 $625 $0 $0 $800 Cash $410 Liquidity 3Q 2026 2026 2027 2028 2029 2030 2031 2032 2033 2034 Outstanding Debt Maturities $ Millions $0 Drawn Credit Facility $410 MM Cash on Balance Sheet(1) ~$1.1 BN Liquidity(1) 0.6x Leverage Ratio(2) $0 DRAWN Refinanced 9% 2029 notes with $800 MM of new 8% 8-year notes
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10 Advantaged Cost Structure + Top Decile Margins 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) Based on Rushmore dataset showing Gulf of America wells from 2000-present. (3) See "Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures. Source: FactSet as of October 16, 2026. Comparable group includes 28 U.S. listed E&P companies with market capitalization of over $1 BN. $5 $10 $15 $20 $25 $30 2023 2024 2025 1Q 2026 2Q 2026 3Q 2026 Advantaged Cost Structure vs Gulf of America E&P Peers(1) Operating Expenses $/BOE Peer E&P 2Q Average $18.55 Talos 2Q $18.25 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 2026E EBITDA Margins Consensus $/BOE $41.95 Talos TOP DECILE Top Decile EBITDA/BOE Margins in the E&P sector(3) Talos 3Q $16.74 0 5k 10k 15k 20k 25k 30k 0 20 40 60 80 100 120 140 Gulf of America Drilling Performance(2) Total Measured Depth (Spud to TD) P10 – 517 ft/day P25 – 400 ft/day P50 – 292 ft/day P75 – 202 ft/day P90 – 151 ft/day Talos Wells CPN Daenerys II Katmai West #2 Daenerys I Sunspear Days Drilled Intervals (ft)
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11 Updated 2026 Operational and Financial Outlook (1) Excludes acquisitions; (2) Includes Lease Operating Expenses and Maintenance; (3) Includes insurance costs; (4) Includes reimbursements under production handling agreements; (5) Excludes non-cash equity- based compensation and transaction and other expenses; (6) Includes cash interest expense on debt and finance lease, surety charges and amortization of deferred financing costs and original issue discounts. * Due to the forward-looking nature a reconciliation of Cash Operating Expenses and G&A to the most directly comparable GAAP measure could not be reconciled without unreasonable efforts. 2026 Production Guidance Considerations • Revised Full-Year 2026 guidance: ‒ Includes the completed Gulf of America acquisition on 9/22 ‒ Includes the impact of the closed non-core shelf divestment on 7/15 ‒ Includes the impact of Hurricane Isaias in early October; 4Q 2026 impact of ~7 MBOE/D Original Guidance ($ Millions, unless highlighted) Revised 2026E Guidance ($ Millions, unless highlighted) Production Avg. Daily Production (MBOE/D) 85 – 90 92.5 – 94.5 Avg. Daily Oil Production (MBO/D) 62 – 66 68 – 70 CAPEX Capital Expenditures(1) $500 – $550 $475 – $525 P&A Expenditures P&A, Decommissioning $100 – $130 $135 – $145 Cash Expenses Cash Operating Expenses and Workovers(2)(3)(4)* $560 – $590 $580 – $600 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 and Bolt-On Acquisition Original Guidance Base Performance Net A&D Revised Guidance 64 midpoint 69 midpoint
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12 Walker Ridge Green Canyon Atwater Valley Mississippi Canyon Ewing Bank Gulf of America Shelf 2 4 3 1 5 6 Ram Powell Facility Pompano Facility Na Kika Facility Tarantula Facility Brutus Facility Talos Acreage Peer Acreage Talos Facility Focused 2026 Development, Exploration and Appraisal Activity Balanced Investment Across Infrastructure-Led Development, Exploration and Appraisal, and Monument 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: September 2026 Brutus Program – Operated • Host Facility: Brutus • Spud Date: 2H 2026 • First Oil Date: 2027 Development Activity 1 2 3 4 Exploration and Appraisal Activity Daenerys – Operated • Host Facility: TBD • Spud Date: 3Q 2026 • TD: 3Q 2026 5 Key Workover Activity Genovesa – Operated • Host Facility: Na Kika • Planned Activity: 2Q 2026 • Return to Production: June 2026 6 First Oil Achieved First Oil Achieved Second Well Spud Monument – Non-Op • Host Facility: Shenandoah • Spud Date: Drilling Underway • First Oil Date: 1Q 2027 Returned to production in June Appraisal Well Drilled to TD Commenced platform-rig operations
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13 Gulf of America Shelf Daenerys – Subsalt Miocene Discovery Appraisal Well Reached Target Depth with Strong Drilling Execution; Additional Activity Planned in 2027 Discovery Well Highlights • Large Miocene structure • Discovery well drilled to total vertical depth of 33,228 ft • 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 Met • Tested the northern part of the prospect; encountered oil pay in multiple high- quality sands • Drilled to total vertical depth of 29,484 ft; drilling performance in the top decile in the Gulf of America • Well designed to allow future sidetracks for further appraisal and/or production • Advancing range of development concepts from tie-back to standalone host • Assess reservoir and fluid properties; samples collected and undergoing testing Future 2027 activity includes a sidetrack to further evaluate Daenerys and an exploration well in late 2027 / early 2028 on Talos leases acquired in BBG1 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% Area Map Complete In Progress In Progress Talos Acreage Atwater Valley Walker Ridge Green Canyon Walker Ridge Green Canyon Daenerys Stones FPSO Heidelberg SPAR
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14 Gulf of America Shelf • Monument #4 well spud in early September • Monument #3 well drilled to TD in June; finding ~250 ft of net TVT oil pay in line with pre-drill expectations • Completion operations on both Monument wells are expected to commence after the second well reaches target depth • First oil is now expected in 1Q 2027, reflecting the operator’s rig redeployment following the Monument #3 well 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 Monument #4 Well Spud Early September; First Oil Expected in 1Q 2027 Operational Update Key Data Points • 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% Background 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 1Q 2027 ~20 - 30 ~91% 30,500 ft Shenandoah Area Map Walker Ridge Green Canyon Atwater Valley Walker Ridge Green Canyon Monument Shenandoah FPS Talos Acreage
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15 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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16 Appendix
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17 (1) Based on gross 2-stream production data. (2) Based on Welligence production data for Gulf of America; cum liquids production for January 2025 to January 2026. Peers in Top 10 include BP, Che vron, 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 reached ~38 MBOE/D in 2026 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 successTarantula 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 Ewing Bank Green Canyon Talos Acreage
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18 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 $6.8 MM gain on the Incremental Mexico Equity Sale. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency and are included in “Other operating (income) expense” on our consolidated statements of operations. (3) The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA attributable to Talos Energy Inc. on an unrealized basis during the period the derivatives settled. (4) One Boe is equal to six MCF of natural gas or one BBL of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. Three Months Ended ($ Thousands) September 30, 2026 June 30, 2026 March 31, 2026 December 31, 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. $(81,244) $149,667 $(256,165) $(202,580) Net income (loss) attributable to noncontrolling interest $185 $222 $161 $(1,031) Net Income (loss) $(81,059) $149,889 $(256,004) $(203,611) Interest expense $40,194 $39,162 $39,178 $40,796 Income tax expense (benefit) $47,111 $44,837 $(65,292) $(48,448) Depreciation, depletion and amortization $233,430 $229,369 $230,384 $243,222 Accretion expense $33,160 $35,908 $34,939 $31,592 EBITDA $272,836 $499,165 $(16,795) $63,551 Impairment of oil and natural gas properties — — $145,018 $170,392 Transaction and other (income) expenses(1) $(994) $1,344 $8,605 $1,100 Decommissioning obligations(2) $(59) $215 $162 $3,010 Derivative fair value (gain) loss(3) $120,576 $(30,549) $173,547 $(30,227) Net cash received (paid) on settled derivative instruments(3) $(29,839) $(74,146) $(22,470) $26,384 (Gain) loss on debt extinguishment $37,389 — — — Non-cash equity-based compensation expense $6,379 $6,409 $5,336 $4,919 Adjusted EBITDA $406,288 $402,438 $293,403 $239,129 Less: adjustment for noncontrolling interest $221 $258 $196 $(1,001) Adjusted EBITDA attributable to Talos Energy Inc. $406,067 $402,180 $293,207 $240,130 Add: Net cash (received) paid on settled derivative instruments(3) $29,839 $74,146 $22,470 $(26,384) Adjusted EBITDA attributable to Talos Energy Inc. excluding hedges $435,906 $476,326 $315,677 $213,746 Production: BOE(4) 8,415 8,529 7,994 8,203 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) $48.26 $47.15 $36.68 $29.27 Adjusted EBITDA attributable to Talos Energy Inc. excluding hedges per BOE(1)(4) $51.80 $55.85 $39.49 $26.06
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19 Non-GAAP Reconciliations (1) Includes settlement of asset retirement obligations. (2) Includes accruals and excludes acquisitions. (3) Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. (4) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. Three Months Ended ($ Thousands) September 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) $325,795 (Increase) decrease in operating assets and liabilities $(53,836) Capital expenditures(2) $(127,883) Decommissioning obligations settled $42 Investment in Mexico $(315) Transaction and other (income) expenses(3) $(994) Decommissioning obligations(4) $(59) Amortization of deferred financing costs and original issue discount $(1,595) Deferred tax expense (benefit) $45,672 Adjustment for noncontrolling interest $(221) Other adjustments $(318) Adjusted Free Cash Flow attributable to Talos Energy Inc. (before changes in working capital) $186,288 Three Months Ended ($ Thousands) September 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. $406,067 Capital expenditures $(127,883) Plugging & abandonment $(49,990) Decommissioning obligations settled $42 Investment in Mexico $(315) Interest expense $(40,194) Current tax (expense) benefit $(1,439) Adjusted Free Cash Flow attributable to Talos Energy Inc. (before changes in working capital) $186,288
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20 Non-GAAP Reconciliations Three Months Ended ($ Thousands) September 30, 2026 Reconciliation of General & Administrative Expenses to Adjusted General & Administrative Expenses: Total General and administrative expense $43,143 Transaction expenses $1,060 Non-cash equity-based compensation expense $(6,379) Adjusted General & Administrative Expenses $37,824
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21 Non-GAAP Reconciliations (1) Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. (3) The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) attributable to Talos Energy Inc. on an unrealized basis during the period the derivatives settled. (4) The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding. Three Months Ended, September 30, 2026 ($ 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. $(81,244) $(0.49) $(0.49) Transaction and other (income) expenses(1) $(994) $(0.01) $(0.01) Decommissioning obligations(2) $(59) $(0.00) $(0.00) Derivative fair value (gain) loss(3) $120,576 $0.72 $0.71 Net cash received (paid) on settled derivative instruments(3) $(29,839) $(0.18) $(0.18) Non-cash income tax expense (benefit) $47,111 $0.28 $0.28 (Gain) loss on debt extinguishment $37,389 $0.22 $0.22 Non-cash equity-based compensation expense $6,379 $0.04 $0.04 Adjusted Net Income (Loss)(4) attributable to Talos Energy Inc. $99,319 $0.60 $0.58 Weighted average common shares outstanding at September 30, 2026: Basic 166,622 Diluted 170,494
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22 Non-GAAP Reconciliations (1) Net Debt / Combined LTM Adjusted EBITDA attributable to Talos Energy Inc. figure excludes the payments of Finance Lease. Had the Finance Lease been included, Net Debt / Combined LTM Adjusted EBITDA attributable to Talos Energy Inc. would have been 0.7x. (2) Combined LTM Adjusted EBITDA attributable to Talos Energy Inc. includes impacts from the completed Gulf of America Bolt-On Acquisition and Non-Core Shelf Divestment. ($ Thousands) September 30, 2026 Reconciliation of Net Debt: 8.000% Second-Priority Senior Secured Notes $800,000 9.375% Second-Priority Senior Secured Notes $625,000 Bank Credit Facility – matures January 2030 — Total Debt $1,425,000 Less: Cash and cash equivalents $(410,155) Net Debt $1,014,845 Calculation of LTM Adjusted EBITDA attributable to Talos Energy Inc.: 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 Adjusted EBITDA attributable to Talos Energy Inc. for three months period ended September 30, 2026 $406,067 LTM Adjusted EBITDA attributable to Talos Energy Inc. $1,341,584 LTM Adjusted EBITDA from Acquired and Divested Assets $355,381 Combined LTM Adjusted EBITDA attributable to Talos Energy Inc. $1,696,965 Reconciliation of Net Debt to Combined LTM Adjusted EBITDA attributable to Talos Energy Inc.: Net Debt / Combined LTM Adjusted EBITDA attributable to Talos Energy Inc. (1)(2) 0.6x
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23 Talos Hedge Book as of October 31, 2026 This reflects volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of October 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) October – December 2026 Fixed Swaps 4,000 $62.50 — — Collar 25,631 — $62.92 $76.87 January – March 2027 Fixed Swaps 8,000 $75.31 — — Collar 27,000 — $62.32 $77.88 April – June 2027 Fixed Swaps 9,000 $73.10 — — Collar 24,000 — $65.73 $78.15 July – September 2027 Collar 15,674 — $66.97 $84.59 October – December 2027 Collar 14,000 — $66.61 $82.14 Natural Gas – HH NYMEX (MMBTU) (Per MMBTU) (Per MMBTU) (Per MMBTU) 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 36,000 — $2.64 $3.50
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24 www.talosenergy.com NYSE: TALO