Exhibit 99.1 January 2023 Investor Presentation

Important Information for Investors and Shareholders Important Information for Investors and Shareholders This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval. In connection with the proposed Merger, Talos has filed with the U.S. Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4, which includes a proxy statement/prospectus of Talos and a consent solicitation statement of EnVen. Talos also plans to file other documents with the SEC regarding the proposed transaction. After the registration statement has been declared effective by the SEC, a definitive proxy statement/prospectus will be mailed to Talos shareholders and a definitive consent solicitation statement will be mailed to EnVen shareholders. INVESTORS AND SHAREHOLDERS OF TALOS ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS (INCLUDING ALL AMENDMENTS AND SUPPLEMENTS THERETO) AND OTHER DOCUMENTS RELATING TO THE PROPOSED MERGER THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED MERGER. Investors and shareholders will be able to obtain free copies of the proxy statement/prospectus/consent solicitation statement and other documents containing important information about Talos and EnVen once such documents are filed with the SEC, through the website maintained by the SEC at http://www.sec.gov. Participants in the Solicitation Talos, EnVen and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies from Talos shareholders in connection with the proposed transaction. Information about the directors and executive officers of Talos is set forth in Talos’s Definitive Proxy Statement on Schedule 14A for its 2022 Annual Meeting of Stockholders, which was filed with the SEC on April 6, 2022. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the proxy statement/prospectus/consent solicitation and other relevant materials to be filed with the SEC when they become available. 2

Cautionary Statements Cautionary StatementRegarding Forward-LookingStatements This presentation contains “forward-looking statements” for purposes of the federal securities laws. All statements, other than statements of historical fact included in this presentation, regarding our strategy, future operations, the impact of regulatory changes, financial position, estimated capital expenditures, production, revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” 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 theoutcomeandtiming of futureevents. 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 the success of the proposed transaction with EnVen Energy Corporation and anticipated future performance of the future company, the success of our carbon capture and sequestration projects, commodity price volatility, sustained inflation and the impact of central bank policy in response thereto, lack of availability of drilling and production equipment and services, environmental risks, orders, regulations and directives issued by the Biden administration and state and local governmental authorities, COVID-19 impacts, the lack of a resolution to the war in Ukraine and its impact on certain commodity markets, the impact of the ongoing sub-surface water flood project in the Phoenix field and any updates to our estimated ultimate recovery from such project, changes to federal income tax laws and regulations, including the Inflation Reduction Act of 2022,, failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects, geologic risk, drilling and other operating risks, well control risk, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, risks related to the integration of recently acquired assets, including the possibility that the anticipated benefits of the acquisitions are not realized when expected or at all, as well as other factors discussed under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021, Quarterly Report on Form 10-Q for the period ended March 31, 2022, Quarterly Report on Form 10-Q for the period ended June 30, 2022, Quarterly Report on Form 10-Q for the period ended September 30, 2022 and other filingswiththeU.S.SecuritiesandExchangeCommission(“SEC”). Should one or more of these 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, 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. All forward-looking statements speak only as of the date hereof. Exceptas otherwiserequiredby applicablelaw,wedisclaim anydutyto updateanyforward-lookingstatements,to reflecteventsor circumstancesafterthedateof thispresentation. ReserveInformation 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 made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. In addition, we use the terms “resource” and “net pay” in this presentation, which are not measures of reserves prepared in accordance with SEC guidelines or permittedto be includedin SEC filings.Theseresourceestimatesare inherentlymoreuncertainthanestimatesof reservespreparedin accordancewithSECguidelines. Unless otherwise indicated, reserve estimates shown in this presentation were prepared based on specified management price parameters of $80.00/bbl of oil and $3.50 per MMBtu of natural gas in perpetuity, rather than price parameters that would be required in a filing with the SEC. We believe that the use of flat pricing provides useful information about our reserves, as the specified prices reflect what we believe to be reasonable assumptions as to average future commodity prices over the productive lives of our properties. However, we caution you that the pricing used in preparing the reserve report is not a projection of future oil and natural gas prices, and should be carefully considered in addition to, and not as a substitute for, SEC prices, when considering our oil, natural gas and NGL reserves. In addition, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms. In this presentation, we use certain broader terms such as “recoverable resources” that the SEC's guidelines strictly prohibit from inclusion in filings with the SEC. These types of estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, are by their nature more speculative than estimates of proved, probable and possible reserves and do not constitute reserves within the meaning of the SEC's rules. These estimatesare subjectto greateruncertainties,andaccordingly,are subjectto a substantiallygreaterrisk of actuallybeingrealized.Investorsareurgedto considercloselythedisclosuresandrisk factorsin thereportswefile withtheSEC. Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assumption that marketdemand and prices for oil and gaswill continue at levels that allow for economic production of these products. The production, transportation and marketing of oil and gas are subject to disruption due to transportation and processing availability, mechanical failure, human error, hurricanes, global political and macroeconomic events and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantlyfromthoseassumed.Therefore,wecan giveno assurancethatourfutureproductionvolumeswill be as estimated. Use of Non-GAAPFinancialMeasures This presentation includes the use of certain measures that have not been calculated in accordance with U.S. generally acceptable accounting principles (GAAP), including EBITDA, Adjusted EBITDA, LTM Adjusted EBITDA, Net Debt and Adjusted Free Cash Flow. Non-GAAP financial measures havelimitationsas analytical toolsandshouldnotbe consideredin isolationor as a substitutefor analysisof ourresultsas reportedunderGAAP. Use of Projections This presentation contains projections, including production volumes and capital expenditures. 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 this presentation. These projections are for illustrative purposes only and should not be relied upon as being indicative of future 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 contained in the projected information. Even if our assumptions and estimates are correct, projections are inherently uncertain due to a number of factors outside our control. Accordingly, there can be no assurance that the projected results are indicative of our future performance after completion of the transaction or that actual results will not differ materially fromthosepresentedin theprojectedinformation.Inclusionof theprojectedinformationin thispresentationshouldnotbe regardedas a representationbyanypersonthattheresultscontainedin theprojectedinformationwill be achieved. Industryand MarketData; Trademarks andTrade Names 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 sources described above. Although we believe these sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness. We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our businesses. This presentation also contains trademarks, service marks and trade names of third parties, which are the property of their respective owners. The use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this presentation may appearwithoutthe®, TMor SM symbols,butsuchreferencesare notintendedto indicate,in any way,thatwewill notassert,to thefullestextentunderapplicablelaw,theirrightsor therightof theapplicablelicensorto thesetrademarks,servicemarks andtradenames. 3

Who We Are Talos Energy is an innovative, § Conventional offshore focus industry-leading energy company focused on Exploration & Production § Carbon capture leadership and Carbon Capture & Sequestration. We are committed to leveraging § Strong cash flow generation profile our technical, operational and commercial expertise to help supply § Solid balance sheet society’s growing need for secure, affordable energy and leading industrial decarbonization efforts § Exploration catalysts for the future while building value for all of our stakeholders. § Natural acquiror 4

Building the Energy Company of Tomorrow GROWTH ADVANCEMENT A COMPLETE IN UPSTREAM OF CCS ENERGY COMPANY Providing safe and Executing large-scale Producing the energy responsible conventional decarbonization solutions needed today and energy resources for today to reduce industrial advancing low carbon and tomorrow emissions solutions for tomorrow 5

Expansive Operational and Geological Footprint 2023 Exploitation River Bend Focus Area Emerging CCS CCS Site Bayou Bend Opportunities CCS Site Pompano Ram Powell Freeport LNG Amberjack CCS Site GC18 Talos Acreage High Talos Seismic Phoenix HP1 Productivity Fairway Emerging CCS Coastal Bend Project Opportunities CCS Site Key Facilities 2023 Exploration Focus Area Proved Reserves by Product Production Mix (4Q22E) Acreage Footprint (000’s) Project Inventory 143 24% 25% 30 Development Oil 36 Oil Deepwater ~162 56 – 57 ~1.2MM 97 347 NGL NGL Shelf MMBOE MBoe/d Acres Projects Exploitation 9% 8% 788 67% 67% Gas Gas CCS Exploration 31 Note: Figures and maps represent Talos standalone and do not include impact of pending acquisition of EnVen Energy Corporation. Reserves figures based on December 31, 2021 reserves utilizing 6 SEC prices of $66.55 WTI and $3.60 HH before differentials in perpetuity. Acreage figures as of October 31, 2022.

3Q 2022 Highlights Advancing key catalysts while achieving the best credit profile in company history § ~$40 million in Adjusted Free Cash Flow (~$266 million YTD) § Record liquidity (>$800 million) and leverage (0.8x) § $140 million in RBL repayments; ~$450 million net debt reduction since “This was a quarter focused on positioning 1Q21 (~$5.40/share) the Company for the future and investing in key catalysts…By focusing on catalysts that are unique to our operating and § Announced strategic acquisition of EnVen Energy; closing business strengths, we believe we can expected by early February 2023 accelerate our ability to provide steady growth and long-term value creation for our shareholders.” § Initiated 2022 deepwater drilling campaign, including Lime - Tim Duncan, CEO Rock, Venice and Rigolets prospects § Spud Puma West appraisal well, results expected early 2023 Notes: Adjusted Free Cash Flow is defined as Adjusted EBITDA minus Capital Expenditures and Plugging & Abandonment minus Interest Expense, shown before changes in working capital. Net debt is defined as Total Debt principal plus the finance lease balance minus cash and cash equivalents. Each are non-GAAP financial measures. See Non-GAAP Reconciliations included in the 7 Appendix.

The Gulf of Mexico – A Significant National Resource One of the largest, most diverse and most prolific basins on Earth Top U.S. Basins by Daily Oil Production Large-Scale Operations from Majors, Independents, Privates 4,500 500 4,000 450 3,500 Second largest oil-producing 400 basin in the United States 350 3,000 300 2,500 250 2,000 200 1,500 150 1,000 100 500 50 - - Permian U.S. Gulf of Bakken Eagle Ford Niobrara Mississippi / Mexico Woodford ~60 ~50% #8 ~2/3 PLATFORMS OF U.S. REFINING CAPACITY TALOS IS A OF BASIN PRODUCTION >1,000’ DEPTH ALONG GULF COAST TOP 10 PRODUCER FROM TOP 4 COMPANIES Note: Basin oil production as of March 1, 2022 per EIA. 2021 production data per Enverus and excludes eight additional operators with production under 35 MBoe/d. 8 Current Oil Production (MBbl/d) 2021 Daily Gross Production (MBoe/d)

A Leading Environmental & Emissions Story GOM Deepwater is an emissions-leading basin; Talos is advancing its long-term GHG goals GHG Intensity by Global Resource Type Talos Scope 1 GHG Intensity Targets (MT CO Equivalent/MBoe) (Gross Operated Production, MT CO Equivalent/MBoe) 2 2 25.0 80 30% Base Reduction 70 Target by 2025 Deepwater provides 20.0 the lowest GHG 60 intensity production 15.3 50 15.0 10-20% Less 40 Than Next Best 40% Stretch 21.8 10.0 Reduction 30 18.2 17.4 Target 15.9 13.1 20 5.0 10 0 - Deepwater Shale Oil Tight Oil Conventional Conventional Heavy Oil Oil Sands 2018 2019 2020 2021 2022 2023 2024 2025 Shelf Onshore Note: Regional GHG Intensity estimates per Wood Mackenzie The Edge. Talos GHG Intensity based upon AQS/GOADS reporting methods utilizing Talos offshore operated production plus third- 9 party operated wells flowing through Talos production facilities. Scope 1 GHG Intensity reduction targets calculated from 2018 baseline.

2022 ESG & TCFD Report Highlights ― Increased alignment with UN SDGs, GRI, and SASB ― First ever Climate Risk & Opportunities report aligned with TCFD ― Expanded ESG Reporting: NOX/SOX/VOC emissions, energy use, water use, hazardous waste, near miss frequency and average training hours data ― Scope 1 Intensity Reduction of 9% Y/Y, 27% from 2018 baseline ― Scope 1 & 2 Intensity 46% less than XOP Index average ― ~1/2 barrel spilled of ~24 million gross barrels produced ― Rolled out FLIR leak detection system to every platform in portfolio ― Recordable Incident Rate (TRIR) reduction of 11% Y/Y, 58% from 2018 baseline ― 40% Y/Y reduction in hand incidents (high frequency injury category) ― 260% increase in community donations from 2020 ― >11,270 HSE training hours for offshore employees, ~2,200 for office employees ― Increased ESG & Safety categories to 20% of executive compensation metrics ― Expanded SSCR committee, hired Chief Sustainability Officer and formed employee- led ESG Committee ― Eliminating staggered Director elections, expanding Board to 8 seats (6 Talos, including CEO, 5 independents, 2 EnVen independents) as part of EnVen transaction CLICK IMAGES TO ACCESS REPORTS 10 Governance Social Environmental Reporting 2022 TCFD REPORT 2022 ESG REPORT

Positive Impacts from the Inflation Reduction Act Offshore Lease Sale Implications Ram Powell VK 988 § Reinstates winning bids from Lease Sale 257 § Talos was one of most active bidders (high bidder MC 68 Pompano on 10 blocks totaling 57k gross acres) MC 69 § Requires holding previously cancelled Gulf of Mexico lease sales (259, 261) GC 154 Amberjack § Granting of future offshore wind leases tied to holding oil and gas lease sales GC 277 MC 31 § Deepwater royalties capped at current rate for 10 years GC 18 MC 117 HP-1 GC 696 Carbon Capture Implications GC 740 § Increases 45Q credit for permanent CO 2 sequestration (1) § Previous $50/ton increased to $85/ton “The [CCC] applauds the enactment of these enhancements, which will be § Adds a direct pay component to the current federal instrumental in scaling the carbon management industry… to achieve midcentury climate targets, while retaining and creating family-sustaining income tax credit structure jobs and safeguarding America’s domestic energy production.” § Extends eligible project start date through 2032 - Carbon Capture Coalition (1) Must meet certain labor requirements. 11

Catalysts Driving Future Value Creation Development & Exploration Pipeline Access to major catalysts is a unique differentiator for Talos and provides the basis for exceptional Unprecedented long-term value creation M&A Opportunity Low Carbon Initiatives 12

Talos Approach to Organic Drilling Opportunities Regional Seismic Database Talos utilizes seismic technology 3 Value- and M&A to build value through High- Focused M&A Impact Exploration drilling opportunities across the full asset lifecycle. Full Lifecycle 2 Asset Investment Management on Acquired Step-Out Approach Infrastructure Exploitation 1 In-Field Reprocessed Development Seismic Data Note: Asset Management consists of expenditures for development-related activities primarily associated with recompletions and improvements to our 13 facilities and infrastructure.

Current Drilling Inventory Locations Ram Powell Pompano Project Inventory Amberjack 30 Development 36 97 Projects Exploitation 2022 Pompano Exploration Rig Program 31 Coelacanth Delta House 2022 Open Talos Facility GC 18 Water Program Other Key Facility Talos Seismic Phoenix HP1 Selected Project Prospect Location 2022 Puma West Appraisal 1H 2023 Pancheron Exploration Prospect (Camellia) Shenandoah 14

Lime Rock & Venice Discoveries Key Highlights § Talos acquired Ram Powell in 2018; Ram Powell Lime Rock / field had produced ~250 MMBOE Venice § Executed multiple asset management projects to increase production, reduce costs rd § Began hosting nearby 3 party Venice discovery, generating material PHA fees § Applied proprietary seismic Ram Powell reprocessing techniques to near- infrastructure area, identifying both Subsea Tiebacks Lime Rock and Venice Talos Acreage § Discovered 20 – 30 MMBOE gross EnVen Acreage recoverable resources, expected to Talos Seismic Lime bring Ram Powell’s production to Rock levels not seen in 15 years once online 15

Lime Rock Discovery – Exploitation Upper Miocene Exploitation Discovery Seismic Overview Key Data Points Lime Rock Spud Date 4Q 2022 Wellbore Expected First Oil 1Q 2024 M66 Sand Est. Resource (Gross MMBOE) 10 – 15 (48% Oil) 78’ net pay Est. Initial Rate (Gross MBOE/D) 8 – 10 Reservoir Depth (Feet TVDSS) 11,415 Working Interest 60% Host Facility Ram Powell § Internally-generated prospect acquired in Lease Sale 256 Locator Map Amplitude Map § Successfully farmed down to targeted 60% working interest M66 Sand 78’ net pay § Discovered 78 feet of net pay in the prolific Upper Miocene M66 sand; Ram Powell excellent rock and fluid properties § Production to flow via subsea tieback to Talos-operated Ram Powell facility Lime Rock § Will collect PHA fees from non-op partners 16

Venice Discovery – Exploitation Exploitation Discovery Identified via Advanced Seismic Analysis Seismic Overview Key Data Points Venice RAM POWELL Spud Date 4Q 2022 Wellbore FIELD Expected First Oil 4Q 2023 Est. Resource (Gross MMBOE) 10 – 15 (34% Oil) Est. Initial Rate (Gross MBOE/D) 8 – 10 M62 Sand 72’ net pay Reservoir Depth (Feet TVDSS) 13,112 Working Interest 60% § Advanced reprocessing showed prior well never reached target Host Facility Ram Powell § Successfully farmed down to targeted 60% working interest § Discovered 72 feet of net pay in the Locator Map M62 Sand Amplitude Map prolific Upper Miocene M66 sand; excellent rock and fluid properties Venice § Production to flow via subsea tieback Ram Powell to Talos-operated Ram Powell facility § Will collect PHA fees from non-op partners § Additional potential behind-pipe opportunities in shallower zones A-13 ST-1 (NDE) 17

M&A Track Record and Opportunity Set Talos has a solid history of successful acquisitions and is well-positioned to execute on future opportunities Talos Track Record Current M&A Landscape § 12 acquisitions since inception§ >$100 billion in divestments targeted by Super Majors alone by 2025 § Proven ability to add value through M&A § Numerous private offshore E&Ps § Basin entry capability demonstrated by Zama § Few capable, positioned offshore consolidators Talos has added over 100 MMBoe of Net Proved Reserves to acquired assets Gulf of Mexico International 300 283 § Technical and § Consistent commercial 250 application “Backyard” of skill sets 200 183 § Synergy potential § Compelling on Gulf of § Deep relationships risk-adjusted Mexico 150 value basis § Large-scale 100 Atlantic assets with Margin huge potential 50 - At Acquisition At YE 2021 Production Since Acquisition Proved Reserves Notes: Divestment volumes and private offshore entity numbers based on company disclosure, third-party research and Talos estimates. 18 Proved (1P) MMBoe (Net)

EnVen Transaction Overview Petronius Pompano Amberjack Contiguous operated asset portfolio provides hand-in-glove fit in deepwater Ram Powell Gulf of Mexico core areas Cognac Lobster Transaction closing expected by early February 2023 Prince GC18 Increases Scale and Diversity Talos Acreage/Facility Phoenix HP-1 EnVen Acreage/Facility Neptune CCS Opportunity Region Accretive to Talos Shareholders Talos Seismic Brutus / Glider De-Leveraging & Credit Enhancing EnVen Statistics (9/30/22 YTD) Catalyst to Optimize Governance ~24 ~$330 ~$158 MBOE/D Million Million Production Adj. EBITDA Adj. Free Cash Flow Notes: Gross acreage increase based on June 30, 2022 figures; Production figures and pro forma percentage oil and percentage deepwater based on FY 2022E production data based on Talos management estimates. Adj. EBITDA and Adj. Free Cash Flow presented inclusive of hedges; Adj. Free Cash Flow defined as Adj. EBITDA less cash taxes, cash interest and capital expenditures, and is 19 presented before changes in working capital.

Applying Expertise Towards CCS E&P CCS Complementary Skill Sets Conventional Reservoir Expertise, G&G Team Significant Gulf Coast / GOM Presence Vast Seismic Database Established Operator & Project Mgmt. Capabilities Strong HSE Track Record Business Development and Commercially Driven 20

2023 CCS Goals Fortifying, Expanding and Advancing the Business § Enhance existing portfolio and increase storage capacity in existing project areas § Expand partnerships in existing project areas § Progress permitting and front-end engineering design (“FEED”) workstreams § Advance and execute active commercial contracts § Develop additional point source projects 21

Talos CCS Project Portfolio: 800 Million MT CO Storage 2 Supporting 150 MTPA of regional emissions on ~80,000 acres 3 1 River Bend (30%) Gulf of Bayou Bend Mexico 2 (25%) Freeport LNG (50%) Coastal Bend (50%) 1. Bayou Bend 2. Freeport LNG 3. River Bend 4. Coastal Bend Industrial Region Beaumont / Port Arthur Brazoria Co. (TX) Baton Rouge / New Orleans Corpus Christi 4 Regional Emissions (MTPA CO ) ~30 ~20 ~80 ~20 2 Lessor State of Texas Freeport LNG Private Landowner Port of Corpus Christi (1) Footprint (Acres) 40,000+ Offshore ~500 Onshore 26,000 Onshore 13,000 Onshore Storage Capacity (MM MT CO ) 225 – 275 ~25 500+ 50 – 100+ 2 Annual Injection Rate (MTPA CO ) 5.0 – 15.0 0.5 – 1.5 5.0 – 15.0 1.0 – 1.5+ 2 Estimated First Injection Late 2025 Late 2024 2026 Late 2026 Partners Carbonvert, Chevron Storegga Storegga, EnLink Midstream Howard Energy (1): River Bend CCS acreage additionally includes 63,000 on right of first refusal in addition to leased 26,000 acres. 22

Bayou Bend CCS Beaumont Key Highlights § Country’s first and only major offshore CCS project, Sabine operated by Talos Lake § High volume of major emissions sources in close proximity to storage site lease Port Arthur ~30 MM MTPA § CCS-As-A-Service model: transportation, sequestration and monitoring per year of regional emissions § Added Chevron to joint venture for $50 million gross consideration; Talos to remain operator § Currently targeting anchor emissions sources to underwrite project FID with initial volumes ― Long-term contracts; high-credit counterparties ― Tolling fee-based cash flow stream ― Incremental emissions will scale project Bayou Bend § 40,000+ Acres CCS Site § Drilling CCS site evaluation well this year to facilitate § 225-275 MM MTPA capacity filing EPA Class VI permit application § 5-15 MM MTPA per year “We determined that TALO’s River Bend and Bayou Bend sites are proximate to the highest point source emission volumes using a twenty-mile buffer.” - Enverus Notes: Emissions sources derived from EPA FLIGHT database. 23

Illustrative CCS Commercial & Economic Considerations Large-scale projects and contracted cash flows with high visibility Incentives Estimated Capture Cost by Industry ($/tonne) § Federal tax credits and direct pay provisions New, Expanded 45Q Credit $100 for Dedicated Storage § State Programs $90 § DOE Funding $80 § Voluntary Carbon Markets $70 Customers $60 § Major industrial partner(s) will underwrite project $50 § Incremental emissions leverage existing $40 Previous 45Q Credit for Dedicated Storage infrastructure $30 $20 Commercial Structure $10 § Long-term tolling agreements with strong credit counterparties $0 § CCS-as-a-Service: Talos JVs to provide bespoke customer solutions ― Striving for value chain to hold equity stakes ― Aligns financial interest ― Mitigates regulatory and performance Source: Enverus, The Energy Futures Initiative, Congressional Research Service; ‘Transport Infrastructure for Carbon Capture and Storage’ Great Plains Institute. 24 $/tonne

Beyond Net Zero PERMANENTLY Executing Decarbonization for Industrial Partners SEQUESTERED CO (MMTPA) 2 § At full scale, Talos CCS will permanently 20.0+ sequester >50x the annual emissions of its Upstream operations § Talos CCS plans to contribute to broad industrial decarbonization well beyond its own Upstream Scope 1 emissions § Sequestration portfolio is diversified with large addressable markets and numerous potential customers § CCS-as-a-Service model, partnering with midstream, provides turn-key emissions reduction solution TALOS UPSTREAM EMISSIONS (MMTPA) (WITH EXISTING CCS 0.4 PORTFOLIO ONLINE) Notes: Upstream data based on offshore operated production plus third-party operated wells flowing through Talos production facilities. Existing CCS portfolio sequestration based on midpoint of gross annual injection rates from existing announced projects. Permanently sequestered CO2 estimates are subject to achievement of full scale CCS operations, which is subject to many 25 uncertainties and may not be achieved on the timeline currently contemplated or at all, and are shown compared to current annual emissions, which may fluctuate or increase over time.

Financial Principles We aim to maximize shareholder value through disciplined investments, healthy credit and responsible risk management. Our key financial principles include: § Appropriate capital reinvestment with positive Adjusted Free Cash Flow generation § Maintain low leverage and high liquidity § Manage maturities and financial obligations for flexibility § Responsible risk management with hedging, insurance, contract management 26

Current Capitalization & Balance Sheet Trends Prioritizing financial health, stability and successful long-term value creation Capitalization Summary ($MM) Liquidity ($MM) $900 Tranche 9/30/22 Maturity $807 $800 $702 RBL Facility ($1,500 BB, $965 Commitments PF EnVen) $60 Mar. 2027 $673 Pandemic $700 $612 $593 12.00% 2L Note (5NC2, Jan. ’23 First Call) 650 Jan. 2026 $546 $546 $600 $516 $473 $500 Finance Lease 20 --- $400 $380 $376 $359 $356 $354 $400 Total Debt 730 --- $300 Cash 64 --- $200 $100 Net Debt $666 --- $- Semi-annual Net Debt / LTM Adjusted EBITDA RBL Balance ($MM) redetermination Pandemic Pandemic successfully completed 3.0x $700 $650 $650 $650 $640 2.7x late December 2022 2.4x $600 2.5x 2.2x 2.2x 2.0x $465 $500 2.0x $400 $400 1.7x 1.7x $375 1.5x $400 $350 $340 1.4x $315 $315 1.3x 1.5x 1.2x $275 1.2x 1.1x $300 1.0x $200 0.8x 1.0x $200 0.5x $60 $100 0.0x $- Notes: Net Debt / LTM Adjusted EBITDA is defined as Net Debt divided by LTM Adjusted EBITDA and is a non-GAAP financial measure. See Non-GAAP Reconciliation under Appendix A. RBL Facility borrowing base and commitments shown pro forma for automatic increases expected in conjunction with 27 closing of the EnVen acquisition. Liquidity and RBL balance figures shown as of September 30, 2022.

28

APPENDIX 29

Non-GAAP Reconciliations Three Months Ended ($ thousands, except per Boe) September 30, 2022 June 30, 2022 March 31, 2022 December 31, 2021 Reconciliation of net income (loss) to Adjusted EBITDA: Net Income (loss) $ 250,465 $ 195,141 $ (66,441) $ 81,012 Interest expense 29,265 30,776 31,490 33,102 Income tax expense (benefit) 121 2,607 (472) (2,353) Depreciation, depletion and amortization 92,323 104,511 98,340 105,900 Accretion expense 13,179 14,844 14,377 14,019 EBITDA 385,353 347,879 77,294 231,680 Write-down of oil and natural gas properties — — — 18,123 (1)(3)(4) Transaction and other (income) expenses 3,239 (5,010) (26,532) 19,710 (2) Derivative fair value (gain) loss (114,180) 64,094 281,219 13,473 (2) Net cash payments on settled derivative instruments (81,162) (160,235) (127,086) (100,912) Non-cash write-down of other well equipment inventory — — — 5,606 Non-cash equity-based compensation expense 4,310 4,049 3,318 2,698 Adjusted EBITDA 197,560 250,777 208,213 190,378 (2) Add: Net cash payments on settled derivative instruments 81,162 160,235 127,086 100,912 Adjusted EBITDA excluding hedges $ 278,722 $ 411,012 $ 335,299 $ 291,290 (1) Includes transaction-related expenses, decommissioning obligations, and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. Transaction-related expenses were $4.5 million, $1.2 million, $1.1 million and $0.5 million for the three months ended September 30, 2022, June 30, 2022, March 31, 2022 and December 31, 2021, respectively. Decommissioning obligation expense was less than $0.1 million, $10.2 million, $0.3 million and $14.2 million for the three months ended September 30, 2022, June 30, 2022, March 31, 2022 and December 31, 2021, respectively. For the three months ended June 30, 2022 there was also a $2.5 million gain related to the settlement of an acquired imbalance. 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 on an unrealized basis during the period the derivatives settled. (2) Includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 for the three months ended March 31, 2022. (3) Includes a $1.4 and $13.9 million gain on partial sale of our investment in Bayou Bend for the three months ended September 30, 2022 and June 30, 2022, respectively. Note: Adjusted EBITDA excluding hedges provides useful information regarding our results of operations and profitability by illustrating the operating results of our oil and natural gas properties without the benefit or detriment, as applicable, of our financial oil and natural gas hedges. By excluding our oil and natural gas hedges, we are able to convey actual operating results using realized market prices during 30 the period, thereby providing analysts and investors with additional information they can use to evaluate the impacts of our hedging strategies over time.

Non-GAAP Reconciliations ($ thousands) September 30, 2022 June 30, 2022 March 31, 2022 December 31, 2021 Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow (before changes in working capital) Adjusted EBITDA $ 197,560 $ 250,777 $ 208,213 $ 190,378 Less: Capital Expenditures and Plugging & Abandonment (128,880) (85,927) (84,706) (64,272) Less: Interest Expense (29,265) (30,776) (31,490) (33,102) Adjusted Free Cash Flow (before changes in working capital) $ 39,415 $ 134,074 $ 92,017 $ 93,004 ($ thousands) September 30, 2022 June 30, 2022 March 31, 2022 December 31, 2021 Reconciliation of net cash provided by operating activities to Adjusted Free Cash Flow (before changes in working capital) (1) Net cash provided by operating activities $ 184,563 $ 240,755 $ 113,610 $ 123,740 (Increase) Decrease in operating assets and liabilities (37,493) (47,635) 73,367 9,479 (2) Investment in properties (108,344) (66,182) (64,683) (54,285) (3) Transaction and Other Expenses 4,651 8,865 (26,532) 19,710 Amortization of Deferred Financing Costs (3,662) (3,537) (3,415) (3,297) Other Miscellaneous Adjustments (300) 1,808 (330) (2,343) Adjusted Free Cash Flow (before changes in working capital) $ 39,415 $ 134,074 $ 92,017 $ 93,004 (1) Includes settlement of asset retirement obligations. (2) Includes accruals and excludes acquisitions. (3) Includes transaction-related expenses, decommissioning obligations, and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. Transaction-related expenses were $4.5 million, $1.2 million, $1.1 million and $0.5 million for the three months ended September 30, 2022, June 30, 2022, March 31, 2022 and December 31, 2021, respectively. Decommissioning obligation expense was less than $0.1 million, $10.2 million, $0.3 million and $14.2 million for the three months ended September 30, 2022, June 30, 2022, March 31, 2022 and December 31, 2021, respectively. For the three months ended June 30, 2022 there was also a $2.5 million gain related to the settlement of an acquired imbalance. 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 31 gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

Non-GAAP Reconciliations September 30, 2022 June 30, 2022 March 31, 2022 December 31, 2021 Reconciliation of Net Debt ($ thousands) 12.00% Second-Priority Senior Secured Notes – due January 2026 $ 650,000 $ 650,000 $ 650,000 $ 650,000 7.50% Senior Notes – due May 2022 — — 6,060 6,060 Bank Credit Facility – matures November 2024 60,000 200,000 340,000 375,000 Finance lease 20,458 27,386 33,965 40,221 Total Debt 730,458 877,386 1,030,025 1,071,281 Less: Cash and cash equivalents (64,490) (108,481) (78,348) (69,852) Net Debt $ 665,968 $ 768,905 $ 951,677 $ 1,001,429 Calculation of LTM EBITDA: Adjusted EBITDA for three months period ended December 31, 2021 $ 190,378 Adjusted EBITDA for three months period ended March 31, 2022 208,213 Adjusted EBITDA for three months period ended June 30, 2022 250,777 Adjusted EBITDA for three months period ended September 30, 2022 197,560 LTM Adjusted EBITDA $ 846,928 Reconciliation of Net Debt to LTM Adjusted EBITDA: Net Debt as of September 30, 2022 / LTM Adjusted EBITDA 0.8x 32