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1 4Q 2025 Earnings Conference Call & Webcast February 25, 2026 www.talosenergy.com NYSE: TALO
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2 Cautionary Statements Cautionary Statements The information in this presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities A ct 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 presentation, 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 presentation, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect ,” “project,” ‘potential,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timin g of future events. These forward-looking statements are based on management’s current beliefs, based on currently available informat ion, as to the outcome and timing of future events. Examples of forward -looking statements include statements about: business strategy; estimated or recoverable resources and reserves; drilling prospects, inventories, projects and programs; our ability to replace the reserves that we produce through drilling, acquisitions, recompletions or enhanced recovery; financial strategy, borrowing ba se under our credit agreement, availability of financing sources and under our credit facility, liquidity position and capital require d 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 including such changes that may be implemented by the current or future administrations or foreign governments, and the impact of such policies on us, our customers and suppliers and the global economic environment; our ability to obtain surety bonds on commer cially reasonable terms; expected collateral requirements under existing or future surety agreements; market factors impacting the a vailability of surety bonds; volatility in the political, legal and regulatory environments where we currently or in the future may oper ate; risks related to future mergers and acquisitions, including the risk that we may fail to realize the expected benefits of any such transaction; timing and amount of future production of oil, natural gas and NGLs and any related impact on global oil prices and domestic oil production; our hedging strategy and results; future drilling plans; availability of pipeline connections and other infrastru cture on economic terms; competition, government regulations, including financial assurance requirements, and legislative and political developments; the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit , surety bonds and other secured debt; our ability to obtain permits and governmental approvals; pending legal, governmental or enviro nmental matters; our marketing of oil, natural gas and NGLs; our integration of acquisitions and the anticipated post -acquisition performance of the Company; future leasehold or business acquisitions on desired terms; costs of developing, acquiring or abandoning proper ties; 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; cre dit markets; 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, timeline and results with respect to our investment in the Za ma asset; uncertainty regarding our future operating results and our future revenues and expenses; anticipated capital efficiency, marg in 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 presentation that are not historical. We caution you that these 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. These risks include, but are not limited to, commodity price volatility; gl obal demand for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies to set and maintain oil pro duction levels 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 and recent U.S. intervention in Venezuela, and their impact on commodity marke ts; the impact of any pandemic and governmental measures related thereto; lack of necessary infrastructure, transportation and storag e capacity as a result of oversupply, government and regulations; political risks, including a global trade war or the impact o f any prolonged federal government shutdown or lapse in federal appropriations that could disrupt our operations and future drillin g plans and opportunities; lack of availability of drilling and production equipment and services; adverse weather events, including tro pical storms, hurricanes, winter storms and loop currents; cybersecurity threats and incidents; elevated inflation and the impact o f central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospe cts or to successfully develop and produce from our current and future discoveries and prospects; geologic risk; drilling and other ope rating 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 the resulting consequences; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adv erse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations; risks to our industry and business operations associated with legal challenges by non-governmental organizations and other groups; and the other risks discussed in “Risk Factors” of Talos Energy Inc.’s 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. 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 presentation 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 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 justi fy revisions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any fu rther production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natu ral gas and NGLs 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 per mitted to be included in SEC filings. These types of estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, are inherently by their nature more speculative than estimates of proved or other reserves prepared in accordance with SEC guidelines and do not constitute "reserves" within the meaning of the SEC's rules. These types of resourc e estimates are subject to greater uncertainties, and accordingly, are subject to a substantially greater risk of actually bein g realized. Investors are urged to consider closely the disclosures and risk factors in the reports we file with the SEC. Production Estimates Estimates for our 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 productio n, transportation, marketing and storage of oil and gas are subject to disruption due to infrastructure constraints, transportat ion, processing and storage availability, mechanical failure, human error, adverse weather conditions such as hurricanes, global political and macroeconomic events and numerous other factors. Our estimates are based on certain other assumptions, such as well performan ce, which may vary significantly 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 Energy 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 and 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 G AAP. 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, production volumes, cash expenses , capital expenditures, P&A expenditures, collateral obligations and interest expense. 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 respect thereto for the purpose of th is presentation. These projections are for illustrative purposes only and should not be relied upon as being indicative of futur e results. The assumptions and estimates underlying the projected information are inherently uncertain and are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those co ntained in the projected information. Even if our assumptions and estimates are correct, projections are inherently uncertain due to a n umber of factors outside our control. Accordingly, there can be no assurance that the projected results are indicative of our future perf ormance 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 projected inform ation will be achieved. Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assum ption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. O ur 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 also based on our good faith estimates, which are derived from our review of internal sources as well as the independent sour ces described above. Although we believe these sources are reliable, we have not independently verified the information and canno t guarantee its accuracy and completeness.
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3 • Realized $72 MM of FCF enhancements in 2025 • Leadership position as the low-cost E&P in GOA • Top Decile EBITDA margin in the E&P sector Building the Foundation To Be a Leading Pure-Play Offshore E&P Improve Our Business Every Day • Target $25 MM of additional free cash flow starting in 2025 and $100 MM in 2026 • Improve business performance and reduce costs to generate more profit Build a Long-lived Scaled Portfolio • Participate in greenfield developments • Continue to explore additional large resource potential • Acquire and develop projects with significant reserves and production • Thoughtfully evaluate significant opportunities within the GOA, as well as in other conventional basins Grow Production and Profitability • Increase production and free cash flow through high-margin projects • Focus on organic growth and supplement with disciplined bolt-on acquisitions • Continue prioritizing the GOA, while expanding focus to other conventional basins Three Strategic Pillars Executing on New Strategy • Initiated production at Sunspear and Katmai West #2 • Debottlenecking efforts leading to increased production at the Katmai Field • Discovery at the Daenerys exploration prospect • Added new prospects at the December 2025 lease sale • Monument multi-well development to spud in 2026, 1st oil expected in late 2026
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4 INVEST • Invested ~$500 MM of capital and generated FCF of ~$420 MM • Delivered reinvestment rate(1) of ~42% (excluding P&A) underpinned by low breakeven projects GROW • Acquired incremental interest in Monument project • Increased inventory from new lease sale prospects • Continue to thoughtfully evaluate significant opportunities within the GOA, as well as in other conventional basins RETURN • Returned ~$120 MM through share repurchases • Reduced outstanding share count by ~7% • Returned ~44% of FCF since announcing framework in 2Q 2025 STRENGTHEN • Maintained low leverage of 0.7x; no near-term maturities • Extended credit facility maturity date to 2030 • Strong liquidity of ~$1 BN; increased cash balance 2025 OutcomesDisciplined Capital Allocation Framework INVEST in projects that generate robust returns throughout the commodity cycles RETURN up to 50% of annual FCF to shareholders STRENGTHEN the balance sheet target long-term leverage of 1.0x or lower GROW via selective accretive growth opportunities Disciplined Capital Allocation Delivering Strong Financial Outcomes (1) Calculated as capital expenditures divided by EBITDA.
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5 (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 December 31, 2025. 2025 Key Takeaways – Delivering on Our Commitments Differentiated Combination of Execution, FCF, Shareholder Returns and Exploration Upside Committed to safety excellence Developed and executing on new strategy to be a leading pure-play offshore E&P Operational excellence delivering solid financial results Generated significant free cash flow Delivered on shareholder returns Exceeded optimal performance plan target for FCF enhancements Announced successful exploration results Delivered on key operational milestones Strengthened balance sheet 4Q RESULTS FULL-YEAR RESULTS 0.0 SIF Serious Injury or Fatality 65 MBO/D Average Oil Production 89 MBOE/D Average Daily Production 73% Oil $240 MM Adj. EBITDA(1) $29/BOE Adj. EBITDA/BOE(1) $21 MM Adj. FCF(1)(2) 0.0 SIF Serious Injury or Fatality 66 MBO/D Average Oil Production 95 MBOE/D Average Daily Production 70% Oil $1.2 BN Adj. EBITDA(1) $35/BOE Adj. EBITDA/BOE(1) $418 MM Adj. FCF(1)(2) $72 MM FCF Enhancements $0 DRAWN Credit Facility 0.7x Leverage Ratio(1) ~$1.0 BN Liquidity(3) $363 MM Cash on Balance Sheet BALANCE SHEET OPTIMAL PERFORMANCE PLAN $16 MM Returned to Shareholders $119 MM Returned to Shareholders
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6 Optimal Performance Plan Delivers $72+ MM in 2025 ~50% is Recurring, Providing Strong Momentum Into 2026 Delivered $72 MM in 2025 2025 Cash Flow Improvements Category Breakdown Margin Enhancement Capital Efficiency Commercial Opportunities Organizational Improvement 2025 $72 MM Delivered Cash Flow Enhancements… • $72 MM realized from the execution of 80+ initiatives • Production Optimization • Pricing Optimization • Logistics and Vessel Efficiencies • Commercial Renegotiations Strong Momentum to Deliver $100+ MM in 2026 …Advancing 2026 Initiatives • 200+ new initiatives being actioned • Production Optimization • Transportation and Logistics Optimization • Supply Chain Optimization • Improved Marketing Contracts • D&C Efficiencies 0 75 150 2025 Actuals 2026E Costs Savings ($ Millions) Generated opportunities with line-of-sight to $100+ MM 3Q 2025 Update Initial 2025 Target $30 MM+ Uplift vs 3Q 2025 Update
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7 Consistently Delivering on Shareholder Returns Returned ~44% of FCF to Shareholders Since Framework Announced in 2Q 2025 $45 $22 $22 $22 $22 $33 $33 $33 $48 $48 $16 2024 1Q 2025 2Q 2025 3Q 2025 FY 2025 Cumulative Value of Shares Repurchased $ Millions ~$45 TOTAL • Returned $119 MM to shareholders in 2025, funded entirely by free cash flow generation • Reduced outstanding share count by ~7% in 2025 • Returned ~44% of FCF to shareholders since announcing return of capital framework in 2Q 2025 $119 TOTAL
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8 $363 $625 $603(3) Availability $625 Cash YE 2025 RBL 2027 9% Notes Due 2029 RBL 2030 9.375% Notes Due 2031 (1) Cash plus available Credit Facility capacity as of December 31, 2025. (2) See “Non-GAAP Information” for details and reconciliations of GAAP to non-GAAP financial measures. Leverage. (3) Availability reflects $97 MM of letters of credit. (4) Reflects volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of February 20, 2026. Balance Sheet Underpins Financial Flexibility to Execute Plan Strong Liquidity Position, Low Leverage and No Near-Term Debt Maturities Cash Balance and Debt Maturities $ Millions ~29 ~27 ~17 ~19 1Q 2026 2Q 2026 3Q 2026 4Q 2026 Average Daily Hedged Oil Volumes(4) MBO/D $0 Drawn Credit Facility $363 MM Cash at Year-End ~$1.0 BN Liquidity(1) 0.7x Maintained Leverage Ratio(2) Hedge positions help protect cash flow in a volatile commodity price environment ~47% of 1Q 2026 oil production (mid-point of guidance) is hedged with avg. price floors above $63/BBL $0 DRAWN Maturity Extended to 2030 ~$63 HEDGE FLOOR ~$60 HEDGE FLOOR ~$60 HEDGE FLOOR ~$62 HEDGE FLOOR
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9 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. 2023 & 2024 based on company SEC filings. 2025 based on: MUR company SEC filings, WTI Bloomberg consensus as of 2/2/26 and KOS YTD 3Q 2025 data. (2) See "Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures. Source: FactSet as of January 13, 2026. Comparable group includes 27 U.S. listed E&P companies with market capitalization of over $1 BN. $16.70 $15.83 2024 2025 Optimal Performance Plan Translating Into Operating Cost Efficiencies Operating Expenses $/BOE $10 $15 $20 $25 2023 2024 2025 Advantaged Cost Structure vs Gulf of America E&P Peers(1) Operating Expenses $/BOE $34.71 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 2025E EBITDA Margin Consensus $/BOE Talos Actual TOP DECILE Top Decile EBITDA/BOE Margin in the E&P sector(2) Peer E&P Avg. $22.24 Talos $15.83
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10 (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 Nov. 2025. Peers in Top 10 include BP, Chevron, Murphy Oil, OXY and Shell. Katmai Field Production Expected to Remain Flat Through 2027 Sustained Debottlenecking Efforts Resulting in Increased Production Recent Highlights • Katmai West #2 first oil achieved in June 2025 • Recent debottlenecking efforts have allowed for increased production from the Katmai Field • Tarantula recently hit sustained output of ~38 MBOE/D through incremental debottlenecking efforts • Katmai Field production is expected to remain flat through late 2027 Locator Map Katmai Field Tarantula Facility Katmai North Prospect Tarantula Facility Facility Prospect Field Talos High-Bid Block Talos Acreage Talos Seismic Future Development Options • Maturing Katmai North with new seismic data • Significant future facility expansion possible with material success at Katmai North 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 Katmai West #1 Peer Peer Peer Peer Peer Cum Liquids MMBbls Katmai West #1 Ranks in Top 10 Wells in the Gulf of America(2)
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11 DevelopmentExploration Other P&A 2026 Budget Overview Prioritizing High-Margin Oil Volumes, Infrastructure-Led Development, and Exploration and Appraisal Activity $600 – $680 MM Total CAPEX Overview • Capital Expenditures guidance of $500 – $550 MM • P&A, Decommissioning of $100 – $130 MM • Production guidance of 62 – 66 MBO/D; 85 – 90 MBOE/D • Focused on high-margin oil production; expect oil cut of ~73% • Balanced investment in infrastructure-led development, exploration and appraisal, and multi- well development at Monument ‒ ~40% of total CAPEX is non-op; driven by Monument ‒ ~10% of total CAPEX allocated to exploration • Total CAPEX weighted ~55% to 1H 2026 • Development project breakevens in the $30s and $40s
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12 2026 Operational and Financial Outlook (1) Excludes acquisitions; (2) Includes Lease Operating Expenses and Maintenance; (3) Includes insurance costs; (4) Includes reimbursements under production handling agreements; (5) Excludes non-cash equity- based compensation and transaction and other expenses; (6) Includes cash interest expense on debt and finance lease, surety charges and amortization of deferred financing costs and original issue discounts. * Due to the forward-looking nature a reconciliation of Cash Operating Expenses and G&A to the most directly comparable GAAP measure could not be reconciled without unreasonable efforts. 2026 Production Guidance Considerations • Annual downtime assumptions include: ‒ 6 MBOE/D of Planned Downtime • Includes 2 MBOE/D related to Genovesa; expected to return to production in 3Q 2026 ‒ 4 MBOE/D of Weather and Other Unplanned Downtime • 1Q 2026 production guidance 60 – 64 MBO/D and 84 – 88 MBOE/D 2026E Guidance ($ Millions, unless highlighted) Production Avg. Daily Production (MBOE/D) 85 – 90 Avg. Daily Oil Production (MBO/D) 62 – 66 CAPEX Capital Expenditures(1) $500 – $550 P&A Expenditures P&A, Decommissioning $100 – $130 Cash Expenses Cash Operating Expenses and Workovers(2)(3)(4)* $560 – $590 G&A(3)(5)* $130 – $140 Interest Expense(6) $155 – $165 2026 Oil Production (MBO/D) Up Year Over Year Excluding Genovesa and Weather Risking 2025 Oil 2026E Genovesa Impact 2026E Oil No storm DT 66 64-1.5 Weather + Unplanned DT
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13 Focused 2026 Development, Exploration and Appraisal Activity Balanced Investment Across Infrastructure-Led Development, Exploration and Appraisal, and Monument Talos Acreage Talos Seismic Talos High-Bid Block 2 3 4 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: 2Q 2026 • First Oil Date: 2H 2026 Monument – Non-Op • Host Facility: Shenandoah • Spud Date: 1Q 2026 • First Oil Date: Late 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: 3Q 2026 • Return to Production: 3Q 2026 6
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14 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 • Named apparent high bidder on 11 OCS blocks; 8 awarded to date • 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 High-Bid Block Katmai Neptune Daenerys
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15 Daenerys Exploration Update Subsalt Miocene Discovery SALT SALT Discovery Well Projected Appraisal Well TBD 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 planned to spud in 2Q 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%
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16 Future P1 Well Future P2 Well Discovery Well WR 272 #1 Discovery Well WR 271 #1 Prospective Drilling Location 2P Reserves • Wilcox discovery with two well penetrations (FID February 2024) • Good seismic image, faulted 4-way closure at ~30,500 ft • 17-mile tieback to new Shenandoah Facility via PHA; committed firm capacity of 20 MBBL/D • Incremental upside of 25 - 35 MMBOE from prospective drilling location • Working Interest: • 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 – High-Impact Subsalt Wilcox Discovery Major Discovery with Material Resource Life Wilcox Structure MapStrategic Elements Spud Date Est. 2P Reserves (Gross MMBOE)(1)(2) First Oil Est. Initial Rate (Gross MBOE/D) Percent Oil Target Depth (Feet TVDSS) Host Facility 1Q 2026 ~115 MMBOE Late 2026 ~20 - 30 ~91% 30,500 ft Shenandoah WR 271 #1 ~270 ft TVD Gross Pay WR 272 #1 ~220 ft TVD Gross Pay Key Data Points Monument Well Logs Future P2 Well Miocene Oligocene Wilcox Cretaceous SALT Future P1 Well Shenandoah
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17 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 Returning Capital to Shareholders • Return up to 50% of annual FCF • Prioritize share repurchases as shareholder return framework Leading Pure-Play Offshore E&P Company • Expertise in exploration, drilling, engineering and subsea completion • Drive operational excellence to generate FCF
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18 Appendix
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19 59%19% 22% Proved PV-10 PDP PDNP PUD 78% 22% Proved Category Mix Proved Developed Proved Undeveloped 75% 6% 19% Proved Product Mix Oil NGL Gas YE 2025 SEC Proved Reserves (1) PV-10 is a non-GAAP financial measure. Figures may not add due to rounding. Notes: This data summarizes year end 2025 reserves of Talos. Reserves volumes may fluctuate slightly based on economic limitations. SEC Reserves figures are presented inclusive of the plugging and abandonment obligations and before hedges, utilizing SEC pricing of $65.39 WTI per BBL of oil and $3.30 HH per MMBTU of natural gas, before differentials. Values in charts and tables may not sum to the total amounts shown, due to rounding. Talos SEC Reserves (MMBOE) SEC PV-10(1) ($BN) PDP 103 $2.4 PDNP 34 $0.4 PUD 38 $0.3 Total Proved (Net of P&A) 175 $3.2 Total Probable (Net of P&A) 103 $2.3 175 MMBOE 175 MMBOE $3.2 $BN
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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 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) December 31, 2025 September 30, 2025 June 30, 2025 March 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. Net income (loss) attributable to noncontrolling interest $(202,580) $(95,905) $(185,937) $(9,868) $(1,031) $(3) — — Net Income (loss) $(203,611) $(95,908) $(185,937) $(9,868) Interest expense $40,796 $40,847 $40,811 $40,927 Income tax expense (benefit) $(48,448) $(24,204) $(36,426) $(91) Depreciation, depletion and amortization $243,222 $262,637 $269,706 $280,716 Accretion expense $31,592 $30,764 $32,046 $30,894 EBITDA $63,551 $214,136 $120,200 $342,578 Impairment of oil and natural gas properties $170,392 $60,209 $223,881 — Transaction and other (income) expenses(1) $1,100 $9,253 $(773) $(4,579) Decommissioning obligations(2) $3,010 $316 $76 $(157) Derivative fair value (gain) loss(3) $(30,227) $(4,226) $(86,855) $15,853 Net cash received (paid) on settled derivative instruments(3) $26,384 $16,605 $33,315 $5,167 Non-cash equity-based compensation expense $4,919 $4,955 $4,403 $4,141 Adjusted EBITDA $239,129 $301,248 $294,247 $363,003 Less: adjustment for noncontrolling interest $(1,001) $8 — — Adjusted EBITDA attributable to Talos Energy Inc. $240,130 $301,240 $294,247 $363,003 Add: Net cash (received) paid on settled derivative instruments(3) $(26,384) $(16,605) $(33,315) $(5,167) Adjusted EBITDA attributable to Talos Energy Inc. excluding hedges $213,746 $284,635 $260,932 $357,836 Production: BOE(4) 8,203 8,757 8,494 9,080 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) $29.27 $34.40 $34.64 $39.98 Adjusted EBITDA attributable to Talos Energy Inc. excluding hedges per BOE(1)(4) $26.06 $32.50 $30.72 $39.41
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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 miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the twelve months ended December 31, 2025, it includes the derecognition of $8.9 MM related to a deferred payment that was deemed uncollectible. (4) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. Three Months Ended Twelve Months Ended ($ Thousands) December 31, 2025 December 31, 2025 Reconciliation of Adjusted EBITDA attributable to Talos Energy Inc. to Adjusted Free Cash Flow attributable to Talos Energy I nc. (before changes in working capital): Adjusted EBITDA attributable to Talos Energy Inc. $240,130 $1,198,620 Capital expenditures $(147,869) $(494,067) Plugging & abandonment $(27,769) $(117,847) Decommissioning obligations settled $125 $(1,102) Investment in Mexico $(2,563) $(4,559) Interest expense $(40,796) $(163,381) Adjusted Free Cash Flow attributable to Talos Energy Inc. (before changes in working capital) $21,258 $417,664 Three Months Ended Twelve Months Ended ($ Thousands) December 31, 2025 December 31, 2025 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) $201,780 $935,826 (Increase) decrease in operating assets and liabilities $16,827 $92,043 Capital expenditures(2) $(147,869) $(494,067) Decommissioning obligations settled $125 $(1,102) Investment in Mexico $(2,563) $(4,559) Transaction and other (income) expenses(3) $1,100 $5,001 Decommissioning obligations(4) $3,010 $3,245 Amortization of deferred financing costs and original issue discount $(1,764) $(8,359) Income tax benefit $(48,448) $(109,169) Adjustment for noncontrolling interest $1,001 $993 Other adjustments $(1,941) $(2,188) Adjusted Free Cash Flow attributable to Talos Energy Inc. (before changes in working capital) $21,258 $417,664
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22 Non-GAAP Reconciliations Three Months Ended Twelve Months Ended ($ Thousands) December 31, 2025 December 31, 2025 Reconciliation of General & Administrative Expenses to Adjusted General & Administrative Expenses: Total General and administrative expense $39,776 $155,368 Transaction and other expenses $(1,525) $(2,964) Non-cash equity-based compensation expense $(4,919) $(18,418) Adjusted General & Administrative Expenses $33,332 $133,986
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23 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 twelve months ended December 31, 2025, it includes the derecognition of $8.9 MM related to a deferred payment that was deemed uncollectible. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. (3) The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) attributable to Talos Energy Inc. on an unrealized basis during the period the derivatives settled. (4) The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding. Three Months Ended, December 31, 2025 Twelve Months Ended, December 31, 2025 ($ Thousands, except per share amounts) Basic per Share Diluted per Share 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. $(203,611) $(1.19) $(1.19) $(494,290) $(2.82) $(2.82) Impairment of oil and natural gas properties $170,392 $1.00 $1.00 $454,482 $2.60 $2.60 Transaction and other (income) expenses(1) $1,100 $0.01 $0.01 $5,001 $0.03 $0.03 Decommissioning obligations(2) $3,010 $0.02 $0.02 $3,245 $0.02 $0.02 Derivative fair value (gain) loss(3) $(30,227) $(0.18) $(0.18) $(105,455) $(0.60) $(0.60) Net cash received (paid) on settled derivative instruments(3) $26,384 $0.16 $0.16 $81,471 $0.47 $0.47 Non-cash income tax benefit $(48,448) $(0.29) $(0.29) $(109,169) $(0.62) $(0.62) Non-cash equity-based compensation expense $4,919 $0.03 $0.03 $18,418 $0.11 $0.11 Adjusted Net Income (Loss)(4) attributable to Talos Energy Inc. $(76,481) $(0.44) $(0.44) $(146,297) $(0.84) $(0.84) Weighted average common shares outstanding at December 31, 2025: Basic 169,789 175,136 Diluted 169,789 175,136
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24 Reconciliation of PV-10 to Standardized Measure (1) All estimated future costs to settle asset retirement obligations associated with our proved reserves have been included in our calculation of the standardized measure for the period presented. (2) Standardized measure is based on management estimates and is not audited by third party reserve engineers. Reconciliation of PV-10 to Standardized Measure Reconciliation of PV-10 to Standardized Measure PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of the Company’s properties. Talos and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. PV-10 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The table below presents the reconciliation of the standardized measure of discounted future net cash flows to PV-10 of our proved reserves: Year Ended ($ Thousands) December 31, 2025 Standardized measure(1)(2) $2,804,857 Present value of future income taxes discounted at 10% $384,180 PV-10 (Non-GAAP) $3,189,037
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25 Non-GAAP Reconciliations (1) Net Debt / Pro Forma LTM Adjusted EBITDA figure excludes the Finance Lease. Had the Finance Lease been included, Net Debt / Pro Forma LTM Adjusted EBITDA would have been 0.8x. ($ Thousands) December 31, 2025 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 March 2027 — Total Debt $1,250,000 Less: Cash and cash equivalents $(362,809) Net Debt $887,191 Calculation of LTM Adjusted EBITDA attributable to Talos Energy Inc.: Adjusted EBITDA attributable to Talos Energy Inc. for three months period ended March 31, 2025 $363,003 Adjusted EBITDA attributable to Talos Energy Inc. for three months period ended June 30, 2025 $294,247 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 LTM Adjusted EBITDA attributable to Talos Energy Inc. $1,198,620 Reconciliation of Net Debt to LTM Adjusted EBITDA attributable to Talos Energy Inc.: Net Debt / LTM Adjusted EBITDA attributable to Talos Energy Inc.(1) 0.7x
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26 Talos Hedge Book as of February 20, 2026 This reflects volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of February 20, 2026. Instrument Type Avg. Daily Volume W.A. Swap W.A. Floor W.A. Ceiling Crude – WTI (BBLs) (Per BBL) (Per BBL) (Per BBL) January – March 2026 Fixed Swaps 15,000 $66.03 — — Collar 14,311 — $59.19 $68.78 April – June 2026 Fixed Swaps 14,000 $65.11 — — Collar 13,000 — $59.62 $69.50 July – September 2026 Fixed Swaps 2,000 $65.00 — — Collar 15,000 — $59.00 $68.87 October – December 2026 Fixed Swaps 4,000 $62.50 — — Collar 14,989 — $59.00 $68.57 Natural Gas – HH NYMEX (MMBTU) (Per MMBTU) (Per MMBTU) (Per MMBTU) January – March 2026 Fixed Swaps 40,000 $4.13 — — April – June 2026 Fixed Swaps 35,000 $3.77 — — July – September 2026 Fixed Swaps 20,000 $3.65 — — October – December 2026 Fixed Swaps 23,315 $3.77 — —
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27 www.talosenergy.com NYSE: TALO