TALO 10-K & 10-Q changes, risk factors and insider trading

We face risks in the normal course of business and through global, regional and local events that could have an adverse impact on our operations and financial performance. The following are some important risk factors that could cause our actual results to differ materially from those projected in any forward-looking statements. If any of the events or circumstances described in any of the following risk factors occurs, our business, results of operations and/or financial condition, as well as the trading price of our common stock and future prospects, could be materially and adversely affected, and our actual results may differ materially from those contemplated in any forward-looking statements we make in any public disclosures.

These risks reflect the Company’s beliefs and opinions as to factors that could materially and adversely affect the Company and its securities in the future. References to past events are provided by way of example only and are not intended to be a complete listing or representation as to whether or not such factors have occurred in the past or their likelihood of occurring in the future. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business.

Among the most significant variable factors impacting our business and financial condition are the sales prices for crude oil and natural gas that we produce.

public health events such as epidemics or pandemics;

political, legal and regulatory instability in regions we currently or in the future may operate, including any prolonged government shutdowns or lapses in appropriations that could disrupt our operations and future drilling plans and opportunities;

Given these various variables, commodity prices are inherently unpredictable. Historically, the markets for oil, natural gas and NGLs have been volatile and remained so during 2025 due in part to geopolitical tensions, the global economy, demand fluctuations, oversupply and macroeconomic uncertainty. As such, prices have been, and may continue to be, subject to wide fluctuations. For example, during the period January 1, 2025 through December 31, 2025, the monthly NYMEX WTI crude oil price per Bbl ranged from a low of $57.97 to a high of $75.74, and the monthly NYMEX Henry Hub natural gas price per MMBtu ranged from a low of $2.91 to a high of $4.26.

Sustained lower oil and natural gas prices adversely affect the Company in several ways:

Lower sales value for our production reduces cash flows and net income.

Lower cash flows may cause us to reduce our capital expenditure program, thereby potentially restricting our ability to replace and grow production and add proved reserves.

Lower oil and natural gas prices could lead to write-downs and impairment charges in future periods, therefore reducing the carrying value of our assets and negatively impacting net income.

Low prices could make a portion of our proved reserves uneconomic, which in turn could lead to the removal of certain of our year-end reported proved oil reserves in future periods. These reserve reductions could be significant.

Lower oil and natural gas prices could lead to an inability to access, renew, or replace our credit facilities, impact our borrowing capacity under our credit facilities, and could also impair access to other sources of funding, potentially negatively impacting our liquidity.

Lower prices could impair our ability to effect share repurchases because of lower cash flows.

If we are unable to replace oil and natural gas reserves, we may not be able to sustain or grow our business.

Our success depends largely upon our ability to find, develop or acquire additional economically recoverable reserves to replace or grow our proved reserves and maintain a portfolio of opportunities for future reserve additions and production over the long-term. Production from existing producing reserves naturally declines over time, requiring perpetual replacement of reserves to maintain or grow production. Our offshore E&P projects require significant upfront capital investment and extended lead times between initial discovery, project sanction and the commencement of production. As a result, changes in commodity prices, costs, market conditions or capital availability during development may negatively impact our ability to complete such projects as planned or to achieve expected returns, which could delay or reduce the addition of new reserves and production. Further, our need to generate revenues to fund operations, contribute to decommissioning activities and collateral obligations, and/or repay debt may also limit our ability to slow or shut-in production during periods of low commodity prices, which may further deplete our reserves during periods where adding reserves is uneconomical.

Exploring for, developing or acquiring reserves is highly capital intensive and uncertain. We cannot assure you that our future exploration, development or acquisition activities will result in additional proved reserves or that we will drill productive wells at acceptable costs. We may be unable to economically find, develop or acquire new reserves, particularly if our operating cash flows decline or capital becomes limited. Current market conditions could further limit financing availability, reduce acquisition opportunities, and/or further depress asset values and prices.

Our production, revenue, reserves, and operating cash flows are derived primarily from properties in the Gulf of America. As a result, we are disproportionately exposed to regional risks such as:

access to, capacity and availability of pipelines, transportation, and/or gathering or processing that we depend on for marketing our production;

We combine our technical experience in geology, geophysics and engineering with innovative resource evaluation techniques and seismic imaging expertise to discover new resources. We rely on our operational experience to optimize our assets’ production and reserve recovery, safely and responsibly. Finally, we leverage our commercial and corporate management experience to most effectively allocate our capital to balance risk and reward, grow our business and maximize long-term stockholder value.

In 2026, we anticipate continued commodity price uncertainty, evolving global macroeconomic conditions, regulatory pressures, and shifting external expectations. Outlooks for crude oil and natural gas prices remain mixed, with some industry sources and analysts expecting prices to soften in 2026 while others anticipate improvement over 2025 levels, reflecting the ongoing unpredictability of global energy markets that will continue to influence the importance of maintaining financial and operational flexibility. Fluctuating commodity prices will directly affect our revenues.

We intend to prioritize high-margin oil production in 2026 underpinned by balanced investment in infrastructure-led development, exploration and appraisal, and multi-well development as part of the Monument Project. Capital expenditures guidance for 2026 is expected to range from $500 to $550 million. Abandonment and decommissioning expenditures are expected to range from $100 to $130 million. Non-operated capital expenditures are expected to be 40% of capital expenditures, which is an increase year over year and largely driven by the Monument Project. Approximately 10% of capital expenditures will be allocated to exploration. Production for 2026 is expected to be in the range of 62 to 66 MBopd; 85 to 90 MBoepd.

Tropical Storm Risk’s extended outlook for the 2026 Atlantic hurricane season indicates activity in line with long‑term averages—14 named storms, 7 hurricanes, and 4 major hurricanes. We incorporate expected weather‑related downtime into our operational and financial planning to maintain flexibility and support achievement of production objectives.

Operational Update

CPN — During the first quarter of 2026, we successfully drilled the CPN well with first production expected in the second half of 2026. The CPN well will tie back to our non-operated Na Kika facility. Talos is the operator of CPN and holds a 65% working interest.

Katmai — The Katmai #2 well came online in the second quarter of 2025. The Katmai Field ties back to our operated Tarantula facility. In connection with the Katmai #2 well coming online, the Tarantula gross processing capacity was expanded to 35 MBoepd to accommodate higher volumes. During the fourth quarter of 2025, gross processing capacity at the Tarantula facility was increased to approximately 38 MBoepd. Talos is the operator of the Katmai Field and holds a 50% working interest.

Genovesa — During the fourth quarter of 2025, we temporarily shut-in production from the Genovesa well, which ties back to the non-operated Na Kika facility, due to a failure of the surface-controlled subsurface safety valve resulting in deferred production of approximately 3 MBoepd. We expect the Genovesa well to return to production in the third quarter of 2026 following completion of a planned workover. Talos is the operator of Genovesa and holds a 65% working interest.

Cardona — We successfully drilled and completed the Cardona well in late 2025. Production from the Cardona well ties back to our Pompano facility. Talos is the operator and holds a 65% working interest.

Manta Ray — During the fourth quarter of 2025, we participated in the drilling of the non-operated Manta Ray well. While the well encountered hydrocarbons, it was deemed non-commercial. Talos held a 40% working interest.

Daenerys — In August 2025, we announced successful drilling results at the Daenerys exploration prospect located on Walker Ridge blocks 106, 107, 150 and 151. The discovery well has been temporarily suspended to preserve its future utility. We plan to spud an appraisal well during the second quarter of 2026 to further define the discovered resource. Talos is the operator of Daenerys and holds a 27% working interest.

Amended and Restated Credit Agreement — On January 20, 2026, we entered into the Amended and Restated Credit Agreement (the “A&R Credit Agreement”) with a syndicate of financial institutions as lenders and JPMorgan Chase Bank, N.A. as administrative agent. The initial borrowing base and the total commitments are each $700 million. The A&R Credit Agreement replaces the Company’s amended credit agreement dated May 10, 2018. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.

Lease Sale — The Big Beautiful Gulf 1 lease sale was held by BOEM on December 10, 2025. It was the first offshore oil and gas lease sale conducted under the new OBBBA. We emerged as the apparent high bidder on eleven of the twelve lease blocks on which we bid. As of February 17, 2026, we have been awarded eight of the lease blocks for which we were the high bidder and are awaiting BOEM’s award decisions on our remaining high bids.

Surety Arrangements and Collateral Requirements — In early November 2025, we entered into various collateral funding and security arrangements (“CFSAs”) to establish limits on the amount of aggregate collateral that our surety providers can require us to post. In exchange for our agreement to post the required amounts of collateral through July 1, 2031 and spend at least a specified amount on annual plugging and abandonment activities each year through 2030, the surety providers agreed not to (1) require additional collateral in excess of the agreed and scheduled amounts on existing surety bonds; (2) draw on collateral posted for the benefit of the sureties except under limited circumstances; (3) seek remedies for breaches of any surety agreement that are not an “Event of Default” as defined in the primary CFSA; or (4) cancel, or attempt to cancel, existing bonds unless requested by us.

For the three years commencing January 1, 2026 and for the subsequent two years commencing January 1, 2029, we are required to spend $90.0 million and $45.0 million on plugging and abandonment activities on an annual basis, respectively. As of December 31, 2025, our aggregate estimated collateral funding commitments under the CFSAs were $251.7 million through 2031. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies— Performance Obligations” for the estimated collateral funding commitments by year under the CFSAs. Also, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Financial Assurance Market Outlook.”

The CFSAs generally contain certain events of default which, if triggered and not cured by us within the cure period, would terminate the standstill period and provide the sureties their full rights under their respective surety and indemnity agreements, including the right to call collateral. Events of default include, but are not limited to, the failure to maintain liquidity of $200.0 million or above a specified credit rating. However, if an event of default were to occur, it is anticipated we would be in a similar position than if we had not entered into the CFSAs given that the surety providers already have the right to demand collateral under existing surety bonds.

The CFSAs provide a multi-year framework to efficiently address the Company’s collateral commitments and abandonment activities, while strengthening the relationship with our surety providers and supporting our long-term operational strategy.

Acquisition of Incremental Working Interest in Mississippi Canyon Blocks — On July 22, 2025, the Company completed the acquisition of an additional 75.2% and 50% working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively, for $33.7 million of cash paid at closing. Prior to this acquisition, we owned an interest in and operated these developed and producing blocks. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Enhanced Corporate Strategy — On June 17, 2025, we announced an enhanced corporate strategy designed to position the Company as a leading pure-play offshore exploration and production company. The strategy is built on three key pillars. The first pillar targets increased annualized free cash flow by improving our existing operations through capital efficiency, margin enhancement, commercial opportunities and general organizational improvements. The second pillar focuses on growth through high-margin organic projects and selective Deepwater acquisitions. The third pillar aims to build a long-lived and scaled portfolio in the U.S. Gulf of America and potentially other conventional basins. This strategy is underpinned by a disciplined capital allocation framework which prioritizes investing in projects expected to generate robust returns through commodity cycles, returning cash to shareholders, maintaining a strong balance sheet, and growing through selective opportunities.

Chief Financial Officer Transition — On May 16, 2025, Sergio L. Maiworm, Jr. informed the Board of Directors (the “Board”) that he was resigning from his position as Executive Vice President and Chief Financial Officer of the Company, effective as of June 27, 2025. In connection with and following Mr. Maiworm’s resignation, effective as of June 28, 2025, Gregory Babcock was appointed as Interim Chief Financial Officer to serve until a permanent Chief Financial Officer was appointed by the Board. On August 12, 2025, the Board appointed Mr. Zachary B. Dailey to serve as the Company’s Executive Vice President and Chief Financial Officer and principal financial officer, effective August 18, 2025.

Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an incremental 8.3% working interest in the Monument oil discovery in the U.S. Gulf of America located on certain Walker Ridge lease blocks. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Appointment of President and Chief Executive Officer — Effective March 1, 2025, Mr. Paul Goodfellow was appointed President and Chief Executive Officer, principal executive officer and as an executive member of the Board.

Share Repurchase Program — During the twelve months ended December 31, 2025, we repurchased 12.6 million shares for $119.1 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board, resulting in $80.9 million available under the share repurchase program. See “Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information.

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile and have remained so during 2025 due in part to geopolitical tensions, the global economy, demand fluctuations, oversupply and macroeconomic uncertainty. As such, oil, natural gas and NGL prices have been, and may continue to be, subject to wide fluctuations. Outlooks for crude oil and natural gas prices remain mixed, with some industry sources and analysts expecting prices to soften in 2026 while others anticipate improvement over 2025 levels, reflecting the ongoing unpredictability of global energy markets that will continue to influence the importance of maintaining financial and operational flexibility. Our revenues, cash flow, profitability, access to capital, capital expenditures, and liquidity are directly influenced by commodity prices, and sustained lower prices could adversely affect our financial results. We use hedging instruments to reduce the impact of near-term price volatility. We also anticipate continuing to operate our business in a volatile market by prioritizing high-return development projects, focusing on cost control measures, and maintaining a strong balance sheet to provide financial, operational and capital spending flexibility under a range of price scenarios. We continue to monitor commodity price trends closely and will modify our plans within our strategy as appropriate. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2025.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of production.

In 2025, the Federal Reserve cut interest rates three times, most recently in December, bringing the federal funds rate down to a target range of 3.50%–3.75%. These cuts mark the lowest rates since 2022. Future changes to the benchmark interest rate remain uncertain.

On May 2, 2025, the DOI announced its intent to revise and develop a new rule that is consistent with the Trump Administration’s 2020 proposed rule on financial assurance. The specific substance and timing of a revised rule cannot be predicted at this time. However, we anticipate that the new revised rule will revert to BOEM’s former policy of considering the financial strength of both co-owners and predecessors in title when determining whether supplemental financial assurance is required, and if so, we anticipate the amount we would be required to bond under the revised rule would be significantly less than under the final rule.

Notwithstanding the status of the final rule or a new revised rule, BOEM stated it will continue to require lessees on the OCS to provide financial assurance in instances where BOEM determines there is a substantial risk of nonperformance of their decommissioning liabilities.

In early November 2025, we entered into CFSAs to establish limits on the amount of aggregate collateral that our surety providers can require us to post through 2031. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” for additional information.

Future Offshore Leasing — Pursuant to OCSLA, the President may withdraw from disposition any of the unleased lands of the OCS. On January 6, 2025, former President Biden issued two memoranda (“Withdrawal Memoranda”) under OCSLA that withdrew approximately 625 million acres of the U.S. OCS, including the Eastern Planning Area of the Gulf of America from being considered for new oil or natural gas leases, including for exploration, development and production. However, the Western and Central Planning Areas in the Gulf of America were not included in President Biden’s withdrawal.

On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s Withdrawal Memoranda and the U.S. Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts. On October 2, 2025, the Western District Court of Louisiana found in part for the plaintiffs challenging the Withdrawal Memoranda, which included the States of Louisiana, Alaska, Georgia and Mississippi, the Gulf Energy Alliance and the American Petroleum Institute, and ruled that the Withdrawal Memoranda are unlawful because they exceed the authority granted to the President under OCSLA. The challenge to President Trump’s revocation of the Withdrawal Memoranda remains ongoing.

Earlier in 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America. In June 2025, the comment period closed regarding BOEM’s notice requesting information and comments on the preparation of the 11th National OCS Program. On November 24, 2025, BOEM announced the availability of a draft proposed program (“DPP”) for OCS oil and gas leasing for the 2026-2031 period. The 2026-2031 DPP proposes a schedule of 34 OCS oil and gas lease sales during this five-year period, which includes 7 lease sales in the Gulf of America. These would be in addition to offshore oil and gas lease sales mandated by law outside the five-year program. We cannot determine when the 11th National OCS Program will be finalized, or how many lease sales will be scheduled.

The OBBBA, signed into law by President Trump on July 4, 2025, mandates that the BOEM conduct at least two offshore lease sales annually, of a minimum of 80 million acres (if available) in the Central and Western Gulf of America Planning Areas for the next 15 years, with at least one of these lease sales to be held by December 15, 2025. The OBBBA reduces the royalty rate for Gulf of America leases acquired at these sales to a minimum of 12.5% (pre-Inflation Reduction Act rates) but not greater than 16.67%. On August 19, 2025, the DOI announced the schedule for the 30 OBBBA-mandated Gulf of America lease sales, the first of which, named the Big Beautiful Gulf 1 Lease Sale was held on December 10, 2025. This lease sale took the place of the previously announced Lease Sale 262, which had been deferred by BOEM. The remaining lease sales are expected to be held each March and August for the years 2026 through 2039, with the last of these mandated Gulf of America lease sales expected in March 2040. On February 4, 2026, BOEM announced its Final Notice of Sale for the Big Beautiful Gulf 2 Lease Sale, which is scheduled to be held on March 11, 2026.

Risks Related to the Pending Transactions

We may not consummate the pending transactions, including the Coulomb and Na Kika Acquisition or the Offshore Mexico Farm-In Transaction on the terms currently contemplated or at all.

We may not consummate various pending transactions on the timeline and terms currently contemplated or at all. For example, the Coulomb and Na Kika Acquisition is subject to the satisfaction of customary closing conditions. These conditions include, but are not limited to, (i) the expiration or termination of any applicable waiting period, or any extension thereof, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and (ii) the absence of any injunction or other order or applicable law preventing or making illegal the consummation of the Coulomb and Na Kika Acquisition. Neither we nor Shell can predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the “Outside Date,” as such term is defined in the Shell Purchase Agreement, it is possible that the Coulomb and Na Kika Acquisition may be terminated. Although Talos Ocho Energy LLC, a Delaware limited liability company (“Talos Ocho”) and RE Fund V Holdco II Infrastructure, LLC, a Delaware limited liability company (“RE Fund” and together with Talos Ocho, the “Buyers”) have agreed with Shell to use commercially reasonable efforts, subject to certain limitations, to promptly complete the Coulomb and Na Kika Acquisition, these and other conditions to the completion of the Coulomb and Na Kika Acquisition may fail to be satisfied. In addition, satisfying the conditions to and completion of the Coulomb and Na Kika Acquisition may take longer, and could cost more, and require additional borrowings, than we currently expect. If additional borrowings are required to consummate the Coulomb and Na Kika Acquisition, our total debt and leverage will be greater than currently anticipated, and our availability under our bank credit facility will be reduced by a corresponding amount.

If (i) the consummation of the Coulomb and Na Kika Acquisition does not occur on or before the Outside Date, or (ii) prior thereto, the Company notifies the trustee that it will not pursue the consummation of the Coulomb and Na Kika Acquisition, the Company will be required to redeem $175.0 million aggregate principal amount of the 8.000% Notes then outstanding on a pro rata basis at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to, but excluding, the special mandatory redemption date; provided that the Company shall not be required to effect more than one special mandatory redemption.

Additionally, the Offshore Mexico Farm-In Transaction is subject to approval by Mexico’s Secretaría de Energía and the National Anti-trust Commission of Mexico. There can be no assurance that closing conditions will be satisfied or that pending transactions, including the Coulomb and Na Kika Acquisition or Offshore Mexico Farm-In Transaction (collectively, the “Pending Transactions”) will be consummated on the terms currently contemplated or at all.

Failure to complete the Pending Transactions on the terms currently contemplated or at all could have a material adverse effect on our results of operations, cash flows and financial position.

If the Pending Transactions are not completed for any reason, including as a result of failure to obtain all requisite regulatory approvals, or if certain expectations with respect to the Pending Transactions are not fully realized (due to reasons including, but not limited to, material inaccuracies in underlying assumptions regarding future reserve and production estimates that could materially affect the benefits expected from these transactions), we may be materially adversely affected and, without realizing any of the benefits of having completed such Pending Transactions on the terms currently contemplated, we would be subject to a number of risks, including the following:

we may experience negative reactions from the financial markets;

we may experience negative reactions from our customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners;

we may still be required to pay certain significant costs relating to the Pending Transactions, such as legal, accounting, and financial advisor fees;

with respect to the Coulomb and Na Kika Acquisition, under certain circumstances, Shell may be entitled to receive the deposit (an interest-bearing amount equal to 5% of the aggregate unadjusted purchase price, with our share being $42.5 million) as liquidated damages pursuant to the Shell Purchase Agreement;

matters relating to the Pending Transactions (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of our management from ongoing business operations and pursuing other opportunities that could be beneficial to us; and litigation related to any failure to complete the Pending Transactions or related to any enforcement proceeding commenced against us to perform our obligations pursuant to each transaction agreement.

If the Pending Transactions are not completed, the risks described above may materialize and they may have a material adverse effect on our results of operations, cash flows, financial position and stock price.

Genovesa — During the fourth quarter of 2025, we temporarily shut-in production from the Genovesa well, which ties back to the non-operated Na Kika facility, due to a failure of the surface-controlled subsurface safety valve. We successfully completed the Genovesa workover and returned the well to production late in the second quarter of 2026.

Monument — As recently announced by the operator, the first Monument development well was successfully drilled to its total measured depth of 32,250 feet and encountered approximately 250 feet of net pay confirming pre-drill expectations. Drilling is set to commence on the second development well followed by completion operations on both wells. First oil is expected by late 2026.

Daenerys — The Daenerys appraisal well was spud on July 1, 2026, and operations are progressing according to plan. Results are expected by year-end 2026.

Pending Coulomb and Na Kika Acquisition — On June 30, 2026, we entered into a purchase and sale agreement to acquire certain oil and gas properties and related assets in the Mississippi Canyon area of the Gulf of America, including interests in the Na Kika and Coulomb Deepwater producing assets for cash consideration of $850.0 million (net to Talos), subject to customary purchase price adjustments (the “Coulomb and Na Kika Acquisition”). The Coulomb and Na Kika Acquisition is expected to close by the end of 2026. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.

Credit Agreement Amendments — On June 30, 2026, we entered into the Borrowing Base Redetermination Agreement, Incremental Agreement, and First Amendment to Amended and Restated Credit Agreement (the “First Amendment”). The First Amendment, among other things, reaffirms the borrowing base at $700.0 million as part of the biannual redetermination of the borrowing base, effective upon closing of the First Amendment. The First Amendment also provides for a borrowing base increase from $700.0 million to $850.0 million subject to and effective upon the consummation of the Coulomb and Na Kika Acquisition. On July 22, 2026, contemporaneously with entry into the farm-in transaction discussed below, we entered into a second amendment to our Amended and Restated Credit Agreement (the “Second Amendment”). See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information regarding the First Amendment and Second Amendment.

8.000% Second-Priority Senior Secured Notes due July 2034 — The $800.0 million 8.000% Second-Priority Senior Secured Notes due 2034 (the “8.000% Notes”) were issued pursuant to an indenture dated July 13, 2026, by and among the Parent Company, Talos Production Inc., as issuer of the 8.000% Notes (“Talos Production” or “Issuer”), the subsidiary guarantors party thereto (together with the Parent Company, the “8.000% Notes Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.

The proceeds from the notes were used to pay related offering fees and expenses and to fund the redemption of all of the outstanding 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”). We intend to use any remaining proceeds to fund a portion of the cash consideration for our pending Coulomb and Na Kika Acquisition.

Redemption of 9.000% Notes — On July 13, 2026, we redeemed all $625.0 million aggregate principal amount of the 9.000% Notes at 104.500% plus accrued and unpaid interest using the proceeds from the issuance of the 8.000% Notes.

Shelf and Gulf Coast Non-Core Properties Divestment — On July 15, 2026, we divested a wholly-owned subsidiary holding non-core, gas weighted and predominantly non-operated Shelf and Gulf Coast properties pursuant to a purchase and sale agreement. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.

Offshore Mexico Farm-In Transaction — On July 22, 2026, we entered into a definitive agreement to farm into the Block 29 development located in the Salinas-Sureste Basin in the southern Gulf of Mexico, operated by a Repsol, S.A. subsidiary (the “Offshore Mexico Farm-In Transaction”). The partners expect to progress the project toward a final investment decision in 2027. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.

Honduras Transaction — On July 29, 2026, we entered into agreements to acquire an 80% operated working interest in an early-phase offshore Honduras project and related seismic evaluation (the “Honduras Transaction”) that provides us access to more than 4 million gross acres. We have closed on a 45% working interest and assumed operatorship. The acquisition of the remaining 35% working interest is subject to approval by Honduras's Secretaría de Energía, which is expected within approximately 90 days. Consideration for the Honduras Transactions includes a reimbursement of sunk costs, a seismic carry, and a contingent discovery bonus. An initial three-dimensional seismic campaign is planned for the second half of 2026.

See Part II, Item 1A. “Risk Factors” of this Quarterly Report and Part II, Item 1A. “Risk Factors” in our 2025 Annual Report for additional information regarding our risk factors.

Six Months Ended June 30, 2026 and 2025 Volumetric Analysis — Production volumes decreased by 5.8 MBoepd to 91.3 MBoepd. This decrease is primarily attributable to a 4.9 MBoepd decline at the Brutus Field, driven by factors mentioned above, as well as a 1.5 MBoepd decrease at the Galapagos Field primarily related to a shut-in due to a failure of the surface-controlled subsurface safety valve at the Genovesa well. We completed the Genovesa workover and returned the well to production late in the second quarter of 2026. These decreases were partially offset by an increase of 3.8 MBoepd related to incremental production at our Sunspear Field.

Six Months Ended June 30, 2026 and 2025 — Lease operating expense for the six months ended June 30, 2026 increased by approximately $19.9 million, or 8%. This was primarily due to an increase in major well workover expenses at the Galapagos Field to return the Genovesa well to production compared to the same period in 2025.

Six Months Ended June 30, 2026 and 2025 — DD&A expense for the six months ended June 30, 2026 decreased by approximately $90.7 million, or 16%. This decrease was primarily driven by a decrease of $3.49, or 11%, in the depletion rate on our proved oil and natural gas properties, as well as decreased production volumes of 5.8 MBoepd discussed above. The change in DD&A rate and decreased production volumes between periods caused DD&A expense to decrease by $57.7 million and $32.8 million, respectively.

Six Months Ended June 30, 2026 and 2025 — General and administrative expense for the six months ended June 30, 2026 increased by approximately $11.6 million, or 16%, primarily driven by higher employee related costs, including non-cash equity-based compensation, compared to the same period in 2025. Additionally, there was an increase in legal expenses related to the lawsuit described above.

Price Risk Management Activities — The income of $30.5 million for the three months ended June 30, 2026 consists of $104.6 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by $74.1 million in cash settlement losses. The income of $86.9 million for the three months ended June 30, 2025 consists of $53.5 million in non-cash gains from the increase in the fair value of our open derivative contracts and $33.3 million in cash settlement gains.

Six Months Ended June 30, 2026 and 2025 —

Impairment of oil and natural gas properties — During the six months ended June 30, 2026, we recorded a $145.0 million impairment of our oil and natural gas properties. During the six months ended June 30, 2025, we recorded a $223.9 million impairment of our oil and natural gas properties. See Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.” for additional information.

Other Operating (Income) Expense — During the six months ended June 30, 2026, we settled a lawsuit for $14.3 million. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information.

Price Risk Management Activities — The expense of $143.0 million for the six months ended June 30, 2026 consists of $46.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $96.6 million in cash settlement losses. The income of $71.0 million for the six months ended June 30, 2025 consists of $32.5 million in non-cash gains from the increase in the fair value of our open derivative contracts and $38.5 million in cash settlement gains.

Equity Method Investment (Income) Expense — During the six months ended June 30, 2026, we recorded equity income of $6.6 million, which includes a $6.8 million gain on the sale of an additional 30.1% equity interest in Talos Energy Mexico 7, S. de R.L. de C.V. (“TEM 7” and the “Incremental Mexico Equity Sale”). See Part I, Item 1. “Financial Statements — Note 6 – Equity Method Investments for additional information.

Income Tax (Benefit) Expense — During the six months ended June 30, 2026, we recorded $20.5 million of income tax benefit compared to $36.5 million of income tax benefit during the six months ended June 30, 2025. See Part I, Item 1. “Financial Statements — Note 10 — Income Taxes” for additional information.