10q10k10q10k.net

What changed in TALOS ENERGY INC.'s 10-K — 2024 vs 2025

vs

Paragraph-level year-over-year comparison of TALOS ENERGY INC.'s 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+473 added−657 removedSource: 10-K (2026-02-25) vs 10-K (2025-02-27)

Top changes in TALOS ENERGY INC.'s 2025 10-K

473 paragraphs added · 657 removed · 259 edited across 7 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

123 edited+116 added−284 removed3 unchanged
Biggest changeThe prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others: • changes in domestic and global supply of and demand for oil and natural gas; • market uncertainty; • level of consumer product demands; • the cost of exploring for, developing and producing oil and natural gas; • changes in climate, weather and natural disasters such as hurricanes and other adverse climatic conditions; • the impact of applicable market differentials, including those relating to quality, transportation, fees, tariffs, energy content and regional pricing; • domestic and foreign governmental actions, regulations and taxes; • price and availability of alternative fuels and competing forms of energy; • political and economic conditions in oil and natural gas producing regions, particularly in the Middle East, Russia, South America, Mexico, Canada and Africa; 30 Table of Contents • armed conflicts and hostilities such as Russia’s ongoing war in Ukraine and hostilities in Israel and the Middle East; • the occurrence or threat of epidemic or pandemic diseases and other public health events; • actions by OPEC Plus and other significant producers and governments relating to oil and natural gas price and production controls; • volatility in the political, legal and regulatory environments in connection with the U.S. and Mexican presidential transitions; • changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements; • price and quantity of oil and natural gas imports and exports; • the level of global oil and natural gas exploration and production and inventories; • localized supply and demand fundamentals and transportation availability; • infrastructure availability and constraints such as capacity of processing, gathering, storage and transportation facilities; • speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; • price and availability of competitors’ supplies of oil and natural gas; • technological advances affecting energy consumption; and • overall economic conditions worldwide.
Biggest changePrices we receive for our oil and natural gas depend on numerous factors beyond our control, including, among others: • domestic and global supply of and demand for oil and natural gas; • market uncertainty and consumer demand levels; • weather and natural disasters such as hurricanes and other adverse climatic conditions; • market differentials, including quality, transportation fees, tariffs, energy content and regional pricing; • domestic and foreign governmental actions, regulations and taxes; • prices and availability of alternative fuels and competing energy sources; • political instability and economic conditions in key producing regions such as the Middle East, Russia, South America, Mexico, Africa and Europe; • armed conflicts and hostilities such as the war in Ukraine and conflicts in Israel and the Middle East; • public health events such as epidemics or pandemics; • actions by OPEC Plus and other major producers and governments regarding production and pricing; • 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; • trade restrictions, tariffs, trade barriers, price and exchange controls; • oil and natural gas import and export levels and prices; • global oil and natural gas exploration, production and inventory levels; • local supply and demand fundamentals and transportation availability; • infrastructure constraints in processing, gathering, storage and transportation; • speculative trading in oil and natural gas futures; • competing supply availability and prices of oil and natural gas; • technological advances affecting energy consumption; and • global economic conditions. 27 Table of Contents Given these various variables, commodity prices are inherently unpredictable.
Also, if material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business.
Also, if material spill incidents occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business.
Certain employment practices and inclusion initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve.
Certain employment or business practices and inclusion initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors. The complex regulatory and legal frameworks applicable to such initiatives continue to evolve.
Subject to the limitations of applicable law, our Second Amended and Restated Certificate of Incorporation, among other things: • permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested; • permits our officers or directors who are also officers, directors, employees, managing directors, or other affiliate of a Principal Stockholder (as defined in the Second Amended and Restated Certificate of Incorporation) to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and • provides that if any of our officers or directors who is also an officer, director, employee, managing director or other affiliate of the Principal Stockholders becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as an director or officer of us), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to any other entity or individual and that director or officer will not be deemed to have acted in a manner inconsistent with his or her fiduciary duty to us or our stockholders.
Specifically, our Second Amended and Restated Certificate of Incorporation: • permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested; • permits our officers or directors who are also officers, directors, employees, managing directors, or other affiliate of a Principal Stockholder (as defined in the Second Amended and Restated Certificate of Incorporation) to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and • provides that if any of our officers or directors who is also an officer, director, employee, managing director or other affiliate of the Principal Stockholders becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as an director or officer of us), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to any other entity or individual and that director or officer will not be deemed to have acted in a manner inconsistent with his or her fiduciary duty to us or our stockholders.
U.S. states in which we operate or own assets may also impose new or increased taxes or fees on oil and natural gas extraction. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect.
It is unclear whether these or similar changes will be enacted and, if enacted, how soon any changes could take effect. In addition, states in which we operate or own assets may also impose new or increased taxes or fees on oil and natural gas extraction.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties affects the timing of actual future net cash flows from reserves, and thus their actual present value.
The timing of both our production and our incurrence of expenses in connection with the development and production of our properties affects the timing of actual future net cash flows from reserves, and thus their actual present value.
All of our U.S. federal NOL carryforwards and certain of our interest expense carryforwards are currently subject to limitation under Section 382 of the Code. In the event that we were to undergo an ownership change in the future, utilization of our NOL and interest expense carryforwards would be subject to limitation under Section 382 of the Code.
Most of our U.S. federal NOL carryforwards and certain of our interest expense carryforwards are currently subject to limitation under Section 382 of the Code. In the event we were to undergo an ownership change in the future, utilization of our NOL and interest expense carryforwards would be subject to further limitation under Section 382 of the Code.
In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes an annual limitation on the amount of NOL and interest expense carryforwards that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code).
In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”) generally imposes an annual limitation on the amount of NOL and interest expense carryforwards that a corporation can use to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code).
From time to time, federal and state level legislation in the United States has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies.
From time to time, U.S. federal and state legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies.
Business and Properties — Government Regulation for additional disclosure relating to the legal requirements imposed by SENER, CNH, ASEA or other Mexican regulatory bodies to which we may be subject in the pursuit of our operations conducted through our equity method investment.
Business and Properties — Government Regulation for additional disclosure relating to the legal requirements imposed by Mexican regulatory bodies to which we may be subject in the pursuit of our operations conducted through our equity method investment.
An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of such corporation’s stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period.
Under Section 382 of the Code, an ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of a corporation’s stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period.
Further, actual future net revenues are affected by factors such as: • the amount and timing of capital expenditures and decommissioning costs; • the rate and timing of production; • changes in governmental legislation, regulations or taxation; • volume, pricing and duration of our oil and natural gas hedging contracts; • supply of and demand for oil and natural gas; • actual prices we receive for oil and natural gas; and • our actual operating costs in producing oil and natural gas.
Further, actual future net revenues are affected by factors such as: • capital expenditures and decommissioning costs; • the rate and timing of production; • changes in laws, regulations or taxes; • volume, pricing and duration of our hedging contracts; • market supply and demand for oil and natural gas; • prices we receive for oil and natural gas; and • our actual operating costs in producing oil and natural gas.
This may cause us to restrict our operations in the U.S. Gulf of America, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could materially and adversely affect our financial condition, cash flows, business properties, liquidity and results of operations. Our actual production could differ materially from our forecasts.
This may cause us to restrict our operations in the areas in which we operate, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could materially and adversely affect our financial condition, cash flows, business properties, liquidity and results of operations. Our actual production could differ materially from our forecasts.
Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses. See Part I, Items 1 and 2. Business and Properties – Insurance Matters for more information on our insurance coverage.
There is no assurance that our insurance coverage will adequately protect us against liability from all potential consequences, damages or losses. See Part I, Items 1 and 2. Business and Properties – Insurance Matters for more information on our insurance coverage.
See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS and Part II, Item 7.
Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS and Part II, Item 7.
The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including: • incurring additional debt; • paying dividends on stock, redeeming stock or redeeming subordinated debt; • making investments; • creating liens on our assets; • selling assets; • guaranteeing other indebtedness; • entering into agreements that restrict dividends from our subsidiaries to us; • merging, consolidating or transferring all or substantially all of our assets; • hedging future production; and • entering into transactions with affiliates.
The agreements governing our debt may impose significant restrictions limiting our ability to take certain actions, including: • incurring additional debt; • paying dividends, redeeming stock or redeeming subordinated debt; • making certain investments; • creating liens; • selling assets; • guaranteeing other indebtedness; • entering into agreements that restrict dividends from our subsidiaries; • merging, consolidating or transferring all or substantially all of our assets; • hedging production; and • entering into certain transactions with affiliates.
If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering.
If we do not have sufficient cash to repay our indebtedness, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering.
No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. Further, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations.
No assurance can be given that we will be able to maintain adequate insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage or self-insure. Further, we may not be able to secure additional insurance or financial assurance surety bonds that might be required by future governmental regulations.
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.
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.
If, due to a redetermination of our borrowing base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency.
If our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such deficiency or take other corrective actions.
As of December 31, 2024, we had approximately $108.7 million of tax-affected U.S. federal NOL carryforwards and $12.4 million of tax-affected state NOL carryforwards. Some of the U.S. federal NOL carryforwards expire in 2036 while others have no expiration date. The state NOL carryforwards have no expiration date.
As of December 31, 2025, we had approximately $139.3 million of U.S. federal tax-affected NOL carryforwards and $16.4 million of state tax-affected NOL carryforwards. Some of our U.S. federal NOL carryforwards expire in 2036 while others have no expiration date. The state NOL carryforwards have no expiration date.
Our Bank Credit Facility allows us to cure a borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding sufficient to cure the borrowing base deficiency within 30 days after the existence of such deficiency; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency or (iv) any combination of the above.
Specifically, we are allowed to cure a borrowing base deficiency by: (i) repaying amounts outstanding sufficient to cure the borrowing base deficiency within 30 days; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency or (iv) any combination of the above.
The rule requires, among other things, that the blowout preventer system is able to close and seal the wellbore at all times to the well’s maximum kick tolerance design limits and includes more stringent requirements for failure reporting.
Effective October 2023, BSEE published a final rule requiring, among other things, that a blowout preventer system is able to close and seal the wellbore at all times to the well’s maximum kick tolerance design limits and more stringent requirements for failure reporting.
While such ratings do not impact all investors’ investment or voting decisions, unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital.
Unfavorable ratings or recommendations may lead to increased negative investor sentiment toward us and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital.
As of December 31, 2024, we also had approximately $75.0 million of tax-affected U.S. federal and state interest expense carryforwards. Utilization of these NOL and interest expense carryforwards depends on many factors, including our future income, which cannot be assured.
As of December 31, 2025, we also had $40.2 million of tax-affected U.S. federal and state interest expense carryforwards. Utilization of these NOL and interest expense carryforwards depends on various factors, including future taxable income, which cannot be assured.
Future tax legislative or regulatory changes in the United States, Mexico or in any other jurisdictions in which we operate or have subsidiaries now or in the future could also adversely impact our after-tax profitability. 43 Table of Contents Our future tax liabilities may be greater than expected if our net operating loss (“NOL”) and interest expense carryforwards are limited.
The passage of any such legislation or other future tax legislative or regulatory changes in the United States, Mexico or in any other jurisdiction in which we operate or have subsidiaries now or in the future could increase our future tax liabilities and adversely impact our after-tax profitability. 36 Table of Contents Our future tax liabilities may be greater than expected if our ability to use our net operating loss (“NOL”) and interest expense carryforwards are limited, which may adversely affect our results of operations and cash flows.
The development of any new material weaknesses in our internal control over financial reporting could result in material misstatements in our consolidated financial statements and cause us to fail to meet our reporting and financial obligations, which in turn could have a negative impact on our financial condition, results of operations or cash flows, restrict our ability to access the capital markets, require significant resources to correct the material weaknesses or deficiencies, subject us to fines, penalties or judgments, harm our reputation or otherwise cause a decline in both investor confidence and the market price of our stock. 47 Table of Contents Risks Related to our Capital Structure and Ownership of our Common Stock Our debt level and the covenants in our current or future agreements governing our debt, including our Bank Credit Facility, and the indentures governing our Senior Notes, could negatively impact our financial condition, results of operations and business prospects.
The development of any new material weaknesses in our internal control over financial reporting could result in material misstatements in our consolidated financial statements and cause us to fail to meet our reporting and financial obligations, which in turn could have a negative impact on our financial condition, results of operations or cash flows, restrict our ability to access the capital markets, require significant resources to correct the material weaknesses or deficiencies, subject us to fines, penalties or judgments, harm our reputation or otherwise cause a decline in both investor confidence and the market price of our stock.
Our leases may expire unless production is established as required by leases covering undeveloped acres. Our drilling plans for areas not held by production are subject to change based upon various factors. As of December 31, 2024, approximately 48% of our net acreage was undeveloped acres. See Part I, Items 1 and 2. Business and Properties—Acreage for further discussion.
As of December 31, 2025, approximately 46% of our net acreage was undeveloped. See Part I, Items 1 and 2. Business and Properties—Acreage for further discussion. Our development plans for areas not held by production are subject to change based upon various factors.
Certain regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-related statements, emission reduction claims, approaches to accounting for GHG emissions reductions, or other ESG-related goals or standards were misleading, false, or otherwise deceptive.
Certain regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private sector actors have also filed lawsuits under various securities and consumer protection laws alleging that certain statements related to environmental, social or governance goals or commitments were misleading, false, or otherwise deceptive.
Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. For example, as a result of ongoing litigation between the U.S.
We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.
Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect.
We also may expand our operations into new jurisdictions which could subject us to additional significant tax liabilities. Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions and interpretations, in each case, possibly with retroactive effect.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. We and other companies in our industry publish sustainability reports that are made available to investors. Such ratings and reports are used by some investors to inform their investment and voting decisions.
In addition, organizations that provide information, ratings or proxy advisory services to investors on corporate governance and related matters have developed processes for evaluating companies on their approach to environmental, social and governance initiatives. Such ratings or recommendations and reports are used by some investors to inform their investment and voting decisions.
Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings.
Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional impairments of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. For the year ended December 31, 2025, the Company recorded an impairment of $454.5 million.
Accordingly, our estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster.
Accordingly, our estimates of future asset retirement obligations and/or decommissioning costs could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. Any unexpected increase in asset retirement obligations and/or decommissioning costs could materially and adversely affect our financial position and results of operations.
Although we do not expect to pay dividends on our common stock, if our Board of Directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us.
Although we do not expect to pay dividends on our common stock in the near term, if our Board of Directors decides to do so in the future, our ability to pay dividends will depend on Talos Production Inc.’s ability to make distributions to us, which is subject to restrictions under its debt agreements and applicable law.
We are required to elect one of the foregoing options within 10 days after the existence of such deficiency. We may not have sufficient funds to make such repayments.
We are required to elect one of the foregoing options within 10 days after the existence of such deficiency. We may not have sufficient cash flows from operating activities to meet our debt obligations.
The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact.
Events such as hurricanes or other natural disasters can also increase costs dramatically if platforms or facilities are damaged or not structurally intact. The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged.
Because oil, natural gas and NGLs accounted for approximately 74%, 19%, and 7%, respectively, of our estimated proved reserves as of December 31, 2024, and approximately 71%, 20%, and 9%, respectively, of our 2024 production on a Boe basis, our financial results are sensitive to movements in oil, natural gas and NGL prices.
Because oil, natural gas and NGLs accounted for approximately 75%, 19%, and 6%, respectively, of our estimated proved reserves as of December 31, 2025, and approximately 70%, 22%, and 8%, respectively, of our 2025 production on a Boe basis, our financial results are particularly sensitive to price movements in these commodities.
In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: • our production is less than expected or is shut-in for extended periods due to hurricanes or other factors; • there is a widening of price differentials between delivery points for our production and the delivery point to be assumed in the hedge arrangement; • the counterparties to our futures contracts fails to perform the contracts; • a sudden, unexpected event materially impacts oil or natural gas prices; or • we are unable to market our production in a manner contemplated when entering into the hedge contract.
In certain circumstances, such transactions may expose us to the risk of financial loss, including instances in which: • our production is less than expected or is shut-in for extended periods; • there is a widening of price differentials between delivery points; • the counterparties default; • there are unexpected market events which materially impact oil or natural gas prices; or • we are unable to market our production as planned.
BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances, such as surety bonds, to assure satisfaction of lease obligations, including decommissioning activities on the OCS.
New surety bonds are not subject to these collateral limits, and we may therefore have to post increased collateral on new bonds. BOEM also requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances, such as surety bonds, to meet lease obligations, including decommissioning activities on the OCS.
Under the Block 7 PSC with the CNH, to which a subsidiary of Talos Mexico is a party, violations of the FCPA, by any signatory to the PSC, may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition.
Under the Block 7 PSC with the CNH, to which a subsidiary of Talos Mexico is a party, violations of the FCPA, by any signatory could result in significant criminal or civil sanctions and allow CNH to rescind the PSC.
The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including: • unexpected drilling conditions; • pressure or irregularities in formations; • equipment failures or accidents; • inflation in exploration and drilling costs; • fires, explosions, blowouts or surface cratering; • lack of, or disruption in, access to infrastructure and transportation; • lack of available skilled labor; and • shortages or delays in the availability of services or delivery of equipment.
Costs of drilling, completion and operation are often unpredictable, and operations may be curtailed, delayed or canceled due to various factors, including: • unexpected drilling or formation conditions; • equipment failures or accidents; • inflation in exploration and drilling costs; • fires, explosions, blowouts or surface cratering; • lack of infrastructure or transportation access; • labor shortages; and • delays or shortages of services or equipment.
While the Delaware courts have determined that choice of forum provisions of this type are facially valid, uncertainty exists as to whether a court would enforce such provision, and as such, a stockholder may nevertheless seek to bring a claim in a venue other than those designated in our exclusive forum provision.
These forum provisions may limit a stockholder’s ability to bring a claim in a forum they find favorable and could discourage lawsuits. While the Delaware courts have determined that choice of forum provisions of this type are facially valid, uncertainty exists as to whether a court would enforce such provision.
Business and Properties — Environmental and Occupational Safety and Health Regulations——Endangered Species Act. 38 Table of Contents Additional drilling laws, regulations, executive orders and other regulatory initiatives that restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to locations where such activities may occur could have a material adverse effect on our business, financial condition or results of operations.
Business and Properties — Environmental and Occupational Safety and Health Regulations. Regulatory changes could restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to leases, which could have a material adverse effect on our business, financial condition or results of operations.
This could result in a current or future tax liability, which could adversely affect our financial condition and cash flows. We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.
This could result in a current or future tax liability and could adversely affect our financial condition and cash flows. We require substantial capital to fund our operations and replace our production and may not be able to obtain financing on acceptable terms. Our business requires substantial capital for acquiring, developing, and producing oil and natural gas reserves.
Additionally, we rely on third-party vendors and service providers, including suppliers, cloud-based storage providers, and industrial equipment manufacturers, which may present additional cybersecurity risks beyond our direct control.
We rely on third-party vendors and service providers, including, but not limited to, software and hardware suppliers, cloud-based service providers, and industrial equipment manufacturers, which may present additional cybersecurity risks to us beyond our direct control if their systems or supply chains are compromised.
For example, during the period January 1, 2022 through December 31, 2024, the daily NYMEX WTI crude oil price per Bbl ranged from a low of $66.61 to a high of $123.64, and the daily NYMEX Henry Hub natural gas price per MMBtu ranged from a low of $1.21 to a high of $13.20.
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.
Risks Related to our Business and the Oil and Natural Gas Industry Oil and natural gas prices are volatile. Stagnation or declines in commodity prices may adversely affect our financial condition and results of operations, cash flows, access to the capital markets and available borrowings under our Bank Credit Facility and our ability to grow.
Risks Related to our Business and the Oil and Natural Gas Industry Oil and natural gas prices are volatile and prolonged price declines could materially adversely affect our business, financial condition, results of operations, cash flows, access to capital, and our ability to replace and grow future production.
The loss of our larger customers could materially reduce our revenue and materially adversely affect our business, financial condition and results of operations. We have a limited number of customers that provide a substantial portion of our revenue.
The loss of a significant customer could materially reduce our revenue and materially adversely affect our business. We rely on a limited number of customers for a substantial portion of our revenue.
Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
Many of these factors are beyond our control, including drilling results, oil and natural gas prices, access to capital, drilling and production costs, service and equipment availability, gathering system and pipeline transportation constraints and regulatory approvals. For acreage we do not operate, we have even less control over development plans, increasing the risk of expiration.
Future exploration and drilling results are uncertain and involve substantial costs. Drilling for oil and natural gas involves numerous risks including the risk that we may not encounter commercially productive reservoirs.
Current market conditions could further limit financing availability, reduce acquisition opportunities, and/or further depress asset values and prices. 28 Table of Contents Future exploration and drilling results are uncertain and involve substantial costs. Drilling for oil and natural gas involves numerous risks, including the risk that we may not encounter commercially productive reservoirs.
Resolution of litigation could materially affect our financial position and results of operations. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we may incur losses that could be material to our financial position or results of operations in future periods. See Part I, Item 3. Legal Proceedings for more information.
Litigation outcomes could materially affect our financial condition. We may be involved in legal proceedings, and an unfavorable resolution could have a material impact on our financial position and results of operations. If potential liabilities are not fully covered by insurance, or if coverage is inadequate, we could incur significant losses. See Part I, Item 3.
We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.
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.
We are subject to income, withholding and other taxes in the United States on a worldwide basis and in numerous state, local and foreign jurisdictions with respect to our income, operations and subsidiaries in those jurisdictions.
In addition, changes in tax laws or their interpretation could increase our tax obligations and reduce after-tax profitability. We are subject to income, withholding and other taxes in the United States on a worldwide basis and in various U.S. state and local and non-U.S. jurisdictions with respect to our income, operations and subsidiaries in those jurisdictions.
Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold federal leases, the federal government requires that we comply with numerous additional regulations applicable to government contractors.
Failure to comply with any regulations applicable to our operations can result in significant administrative, civil or criminal penalties, injunctions and other restrictions on our operations or reputational harm. In addition, because we hold federal leases, the U.S. federal government requires us to comply with numerous additional regulations applicable to government contractors.
Additionally, we are a signatory to the Block 7 PSC, making us jointly and severally liable for the performance of all obligations under the PSC, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations. Failure to perform such obligations could result in contractual rescission of the PSC.
Additionally, under our Block 7 PSC, we are jointly and severally liable for all obligations under the PSC, including exploration, development, appraisal, extraction, abandonment and environmental compliance. Failure to meet these obligations could result in penalties or contractual rescission of the PSC. See Part I, Items 1 and 2.
We have previously adopted, and may again in the future choose to adopt, a stockholder rights agreement, which, if adopted, could have certain anti-takeover effects. Our stock price could also be subject to significant fluctuations or otherwise be adversely affected by the events, risks and uncertainties of any stockholder activism. Item 1B. Un resolved Staff Comments None.
These activities could negatively affect our ability to execute our strategic plan and cause our stock price to fluctuate. We have previously adopted, and may again in the future choose to adopt, a stockholder rights agreement, which, if adopted, could have certain anti-takeover effects. Item 1B. Un resolved Staff Comments None.
We are not insured against all of the operating risks to which our business is exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events.
Any prolonged disruption could materially affect our production, revenue, and financial condition. 34 Table of Contents We are not insured against all of the operating risks to which our business is exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed.
Further information about these commitments can be found under Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies . We have operations in multiple jurisdictions, including jurisdictions in which the tax laws, their interpretation or their administration may change.
These outcomes could materially and adversely affect our results of operations and financial condition. Further information about these commitments can be found under Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies . We have operations in multiple jurisdictions and our tax obligations and related filings are complex.
We previously identified material weaknesses in our internal control over financial reporting that could have, had they not been remediated, resulted in material misstatements in our financial statements and caused us to fail to meet our reporting and financial obligations.
In addition, a government shutdown could affect supply-chain timing and create macroeconomic uncertainty that affects commodity markets and project financing which could materially adversely affect our financial condition, liquidity and results of operations. 39 Table of Contents We previously identified material weaknesses in our internal control over financial reporting that could have, had they not been remediated, resulted in material misstatements in our financial statements and caused us to fail to meet our reporting and financial obligations.
The loss of our larger customers, such as Shell Trading (US) Company and Exxon Mobil Corporation, could adversely affect our current and future revenue, and could have a material adverse effect on our business, financial condition and results of operations. See Part IV, Item 15.
The loss of any large customer, such as Shell Trading (US) Company, Exxon Mobil Corporation and Chevron Corporation, which represent 35%, 23% and 12% of our oil, natural gas and NGL revenues for the year ended December 31, 2025, respectively, could have a material adverse effect on our business, financial condition and results of operations. See Part IV, Item 15.
Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook. Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptions.
Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook. 32 Table of Contents Technology and cybersecurity threats could disrupt our operations and cause reputational and financial harm to our business.
We are subject to the U.S. Foreign Corrupt Practices Act and may be exposed to liabilities thereunder. We are subject to the U.S. Foreign Corrupt Practices Act (the “FCPA”) and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business.
Foreign Corrupt Practices Act, could result in severe penalties and loss of key contracts. We are subject to the U.S. Foreign Corrupt Practices Act (the “FCPA”) and similar laws that prohibit improper payments or offers of payments to foreign officials and political parties to obtain or retain business.
Management, under the oversight of our Audit Committee, took steps to fully remediate the material weaknesses as described more fully in Part II, Item 9A. Controls and Procedures of this Annual Report. We can give no assurance that additional material weaknesses will not arise in the future.
In September 2024, the Company identified two material weaknesses. Management, under the oversight of our Audit Committee, took steps to fully remediate the material weaknesses as described more fully in Part II, Item 9A. Controls and Procedures of our Annual Report on Form 10-K for the year ended December 31, 2024.
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.
The majority of our sales are based on the spot market and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.
In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase.
The risk that we are required to impair the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, impairments may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase.
Further, as a result of adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of surety companies have left the offshore surety market, which has materially reduced the availability of surety bonds for projects in the OCS and may reduce the ability of companies operating in the OCS to obtain bonding without posting collateral.
The offshore surety bond market has undergone a structural shift driven largely by adverse developments in restructurings and bankruptcies of companies operating in the OCS, leading to materially reduced availability of surety bonds as a number of surety companies have exited the offshore surety market.
Accordingly, we are dependent upon distributions from Talos Production Inc. to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. We have no independent means of generating revenue.
As a holding company, we depend on distributions from Talos Production Inc. and our subsidiaries to meet our obligations. We are a holding company that has no material assets other than our ownership of Talos Production Inc. We have no independent source of revenue.
As a result, bonds may not be available to us on commercially reasonable terms, including requiring collateral, which may lead to significantly increased costs on our operations. Further, there may not be sufficient surety bond capacity available for companies in the OCS which could consequently have a material adverse effect on our ability to conduct our operations.
In addition, remaining surety companies generally have a lower risk tolerance which has increased pressure to provide collateral on existing and new surety bonds. As a result, new surety bonds may not be available to us on commercially reasonable terms, including requiring collateral, which may lead to significantly increased costs on our operations.
Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. See Part I, Items 1 and 2.
Our reserves may also be affected by production from adjacent properties operated by others. We regularly revise our estimates to reflect new data, production history, results of exploration and development, changes in prices, and production results. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion on 2025 changes in estimates of our proved reserves.
Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present, produce in economic quantities. We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire.
Seismic data interpretation does not guarantee the presence of commercially viable hydrocarbons. We rely on three-dimensional seismic studies to evaluate drilling opportunities on our properties and potential acquisitions. These studies are interpretive tools and cannot ensure that hydrocarbons are present or, if present, that they can produce in economic quantities.
Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic region, making us vulnerable to risks associated with operating in one geographic area. We currently operate in a concentrated geographic region, in the U.S. Gulf of America and in the shallow waters off the coast of Mexico.
Our current operations are primarily concentrated in a single geographic region, making us vulnerable to regional risks. Our production, revenue, reserves, and operating cash flows are derived primarily from properties in the Gulf of America.
Any of these industry operating risks could have a material adverse effect on our business, results of operations and financial condition. Competition within our industry may adversely affect our operations. Many of our competitors are larger and have more available financial resources.
Any of these events could have a material adverse effect on our business, financial condition, and results of operations. 35 Table of Contents Intense industry competition could limit our growth and increase costs. We operate in a highly competitive industry where many of our competitors are larger and have substantially greater financial resources.
We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named U.S. Gulf of America windstorm, oil pollution, construction risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance.
Gulf of America windstorm, oil pollution, construction risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles or retentions, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and we may experience production interruptions for which we do not have production interruption insurance.
An operational or hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest.
For example, a hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named U.S.
We cannot provide assurance that we will be able to satisfy collateral demands. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position would be significantly negatively impacted, and we may be required to seek alternative financing.
Collateral in the form of cash or letters of credit would negatively impact our liquidity position, and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. See Part I, Items 1 and 2.
We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.
Our growth strategy includes pursuing acquisitions. However, we may not achieve anticipated benefits such as increased earnings, cost savings, operational efficiencies, or reserve additions. Challenges may include higher-than-expected costs, inaccurate reserve estimates, unknown liabilities, challenges operating in new geographic regions and under new regulatory frameworks, and difficulties integrating operations, systems, corporate functions, and personnel.
As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated.
As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated. Our after-tax profitability depends on numerous factors, including the availability of tax deductions, credits, exemptions, refunds and other benefits to reduce our tax liabilities, the allocation of earnings among jurisdictions, and the treatment of intercompany transactions.
To the extent Talos Production Inc. has available cash, we will cause Talos Production Inc. to make distributions of cash to us, directly and indirectly through our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock.
We rely on cash distributions from Talos Production Inc. to pay taxes, cover corporate expenses, and, if declared, pay dividends on our common stock.
These policy, legislative and regulatory changes could ultimately decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.
These legislative and regulatory changes could ultimately decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business. Additional federal, state, and local initiatives, including potential carbon taxes, cap‑and‑trade programs, mandatory GHG reporting, and rules that directly limit emissions, could further increase compliance costs or restrict development activities.

… 443 more changes not shown on this page.

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

12 edited+7 added−4 removed10 unchanged
Biggest changeOur customers, suppliers, subcontractors and joint venture partners face similar cybersecurity threats, and a cybersecurity incident impacting us or any of these entities could materially adversely disrupt our operations, including our drilling operations, and affect our performance and results of operations. Although we believe we have implemented comprehensive cybersecurity measures, no security program is infallible.
Biggest changeA significant cybersecurity incident impacting us or third parties with whom we do business could materially and adversely disrupt our operations and affect our business strategy and performance, financial condition and results of operations. Although we believe we have implemented comprehensive cybersecurity measures, no security program is infallible. For additional information about cybersecurity risks, please see Part I, Item 1A.
To serve as an additional protection from outside threats, we also seek to prepare our employees and contractors about cybersecurity risks through cybersecurity training, simulated phishing exercises and awareness campaigns. We conduct employee training bi-annually, and point-in-time training for any phishing failures.
To serve as an additional protection from outside threats, we also seek to prepare our employees and contractors about cybersecurity risks through cybersecurity training, simulated phishing exercises and awareness campaigns. We routinely conduct employee training, and point-in-time training for any phishing failures.
Management’s Role in Assessing and Managing Cybersecurity Threats — Our information technology team is responsible for assessing, identifying and managing cybersecurity risks. Top cybersecurity risks are also integrated into our overall ERM framework and overseen at the management level by the ERM Steering Committee.
Management’s Role in Assessing and Managing Cybersecurity Threats — Our CIO is responsible for assessing, identifying and managing cybersecurity risks and is supported by the cybersecurity team . Top cybersecurity risks are also integrated into our overall ERM framework and overseen at the management level by the ERM Steering Committee.
As of the date of this Annual Report, we are not aware of previous cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, although the Company regularly experiences cybersecurity incidents that are not deemed material to our operations.
As of the date of this Annual Report, we are not aware of any cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, although the Company periodically experiences cybersecurity incidents that are not deemed material to our business.
Examples of cybersecurity threats we face include incidents common to most companies in the energy industry, such as phishing, business email compromise, ransomware and denial-of-service, as well as attacks from more advanced sources, including nation state actors, that target companies in the energy industry.
Other examples of cybersecurity threats we face include incidents common to most companies in the energy industry, such as phishing, business email compromise, ransomware and denial-of-service, as well as attacks from more advanced sources, including nation state actors, that target companies in the energy industry. Our customers, suppliers, subcontractors and joint venture partners face similar cybersecurity threats.
Our Director of Information Technology, who reports directly to the CFO and Executive Vice President (“EVP”) and is a member of the ERM Steering Committee , is responsible for our efforts to comply with applicable cybersecurity standards, establish cybersecurity protocols and protect the integrity, confidentiality and availability of our information technology infrastructure.
The CIO, who reports directly to the CFO and is a member of the ERM Steering Committee , is responsible for our efforts to comply with applicable cybersecurity standards, establish cybersecurity protocols and protect the integrity, confidentiality and availability of our information technology infrastructure. Technology and cybersecurity policy decisions are made by our CIO in consultation with our CFO.
Cybersecurity risk is reviewed by a cross-functional, management-level ERM Steering Committee as part of the Company’s overall enterprise risk management program. 54 Table of Contents Board of Directors’ Oversight of Risks from Cybersecurity Threats — The Board of Directors is aware of the importance of managing risks associated with cybersecurity threats.
Cybersecurity risk is reviewed by a cross-functional, management-level ERM Steering Committee as part of the Company’s overall enterprise risk management program . 43 Table of Contents Board of Directors’ Oversight of Risks from Cybersecurity Threats — The Audit Committee has been delegated responsibility by the Board for overseeing the Company’s overall enterprise risk management program, including cybersecurity risk.
To further enhance the capabilities of our internal systems, we utilize third-party vendors to provide extended coverage of our information technology and operational technology environments. We also share and receive threat intelligence with companies in the energy sector, government agencies, information sharing and analysis centers and cybersecurity associations in order to monitor and address developments in the cybersecurity environment.
We also share and receive threat intelligence with other companies in the energy sector, government agencies, information sharing and analysis centers and cybersecurity associations in order to monitor and address developments in the cybersecurity environment.
Technology and cybersecurity policy decisions are made by our Director of Information Technology in consultation with our CFO and EVP. In addition, our Director of Information Technology has a direct line of communication with the Office of the Interim Chief Executive Officer and General Counsel as needed.
In addition, our CIO has a direct line of communication with the Chief Executive Officer and General Counsel, as needed.
Our cybersecurity team actively works to assess, identify and manage risks in our information systems in order to protect the confidentiality, integrity and availability of our digital infrastructure. The cybersecurity team meets regularly to evaluate potential threats, discuss best practices and identify new solutions to help mitigate cyber risks.
In November 2025, we appointed a Vice President - Chief Information Officer (“CIO”) to oversee our cybersecurity team, which actively works with third-party service providers to assess, identify and manage risks in our information systems in order to protect the confidentiality, integrity and availability of our digital infrastructure.
Item 1C. Cybersecurity Assessing, Identifying and Managing Cybersecurity Risks — We strive to align our cybersecurity operating model with the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework to enhance our ability to protect, detect, respond, and recover from potential cybersecurity threats.
In addition, we maintain policies and procedures designed to assess, identify and manage cybersecurity threats and incidents and strive to align our cybersecurity operating model with the National Institute of Standards and Technology Cybersecurity Framework (“NIST CSF”).
For additional information about cybersecurity risks, please see Part I, Item 1A. Risk Factors — Risks Related to our Business and the Oil and Natural Gas Industry — Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptions.
Risk Factors — Risks Related to our Business and the Oil and Natural Gas Industry — Technology and cybersecurity threats could disrupt our operations and cause reputational and financial harm to our business.
Removed
We engage third-party service providers to conduct evaluations of our cybersecurity controls through penetration testing, independent audits and consulting on best practices to address existing and new challenges. These evaluations include testing the design and operational effectiveness of our cybersecurity controls. Going forward, we are committed to conducting these evaluations at least annually.
Added
Item 1C. Cybersecurity Assessing, Identifying and Managing Cybersecurity Risks — We rely extensively on information technology (“IT”) and operational technology (“OT”) systems to support exploration, drilling, production, and administrative functions across our offshore and corporate operations. These systems include process control systems on production platforms, remote monitoring systems, and enterprise IT applications for finance, human resources, and supply chain management.
Removed
The Audit Committee has been delegated responsibility by the Board for overseeing the Company’s overall enterprise risk management program, including cybersecurity risk.
Added
Our cybersecurity program is designed to protect these systems from unauthorized access, data breaches, ransomware, and other cyber threats. We aim to implement industry-standard security measures including network segmentation, firewalls, intrusion detection, endpoint protection, multi-factor authentication, incident response plans, security awareness training, and regular security audits.
Removed
The Audit Committee receives reports at least quarterly from the Director of Information Technology regarding cybersecurity matters, which may include, among other things, the results of cybersecurity audits, cybersecurity maturity assessments, other information technology matters, risk mitigation strategies, data protection and progress on initiatives.
Added
We do not represent that our practices conform to any specific technical standards or requirements; rather, we utilize the NIST CSF as a framework that informs how we design our approach to identify, evaluate, and address cybersecurity risks in our operations.
Removed
Our Director of Information Technology has over 20 years of experience in cybersecurity, holds a Master of Science in Cybersecurity from the University of Houston and is a Certified Information Systems Security Professional and a Boardroom Certified Qualified Technology Expert.
Added
The cybersecurity team meets regularly to evaluate potential threats, discuss best practices and identify new solutions to help mitigate cyber risks. Our third-party service providers provide extended coverage of our information technology and operational technology environments and conduct regular evaluations of our cybersecurity controls, including testing the design and operational effectiveness of our cybersecurity controls.
Added
The Audit Committee oversees our cybersecurity policies, procedures, risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. Our cybersecurity team regularly updates and reports to the Audit Committee regarding cybersecurity risk exposure and our cybersecurity risk management strategy.
Added
Our CIO has over 30 years of experience in information technology and cybersecurity, holds a Bachelor of Science from Royal Holloway, University of London and has performed the role of CIO for over 7 years within a leading upstream E&P Company including the responsibility and accountability to the Audit Committee for cybersecurity.
Added
For example, a cyber-attack on a production control system could result in significant environmental and safety risks, such as a well incident, shut-in or spill that could cause business interruption, reputational damage, regulatory fines and penalties, costs of compliance and remediation or insurance limitations.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

6 edited+2 added−8 removed13 unchanged
Biggest changeLegal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters. See Part IV, Item 15.
Biggest changeAccordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for more information. Item 4.
Item 3. Legal Proc eedings We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition. 55 Table of Contents On June 13, 2024, Equinor USA E&P Inc.
Item 3. Legal Proc eedings We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition. 44 Table of Contents On June 13, 2024, Equinor USA E&P Inc.
That appeal was resolved by the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) on December 15, 2022, and on December, 22, 2022, plaintiffs filed a motion in federal court to re-open the lawsuit. Plaintiffs filed motions to remand, which the District Court granted, along with the defendants’ motion to stay the remand order pending appeal.
That appeal was resolved by the United States Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) on December 15, 2022, and on December, 22, 2022, plaintiffs filed a motion in federal court to re-open the lawsuit. Plaintiffs filed motions to remand, which the District Court granted. The defendants that filed the removal have appealed the order of remand.
Since remand, the three Jefferson Parish state court cases involving Stone have been relatively dormant, but one was recently set for trial in October 2026. 56 Table of Contents On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees.
On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees.
Talos ERT will continue to vigorously defend against Equinor’s claims and pursue its counterclaim. The trial is currently scheduled for 2026, although Talos ERT intends to file dispositive motions before then. In June 2019, David M.
Talos ERT will continue to vigorously defend against Equinor’s claims and pursue its counterclaim. The trial is currently scheduled for 2026 but may be continued until 2027.
Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for more information. Item 4. Mine Saf ety Disclosures Not applicable. 57 Table of Contents PART II
Mine Saf ety Disclosures Not applicable. 45 Table of Contents PART II
Removed
Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor of Mr.
Added
Since the remands to state court, the three Jefferson Parish state court cases involving Stone have been relatively dormant. Only one of these cases has been set for trial, for the October-November 2027 docket.
Removed
Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023, which was denied on January 26, 2024.
Added
Since the remand to state court, this case has been relatively dormant and has not been set for trial. Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation.
Removed
The Company paid the judgment of $14.4 million, inclusive of Mr. Dunwoody’s legal fees and interest, during the three months ended March 31, 2024.
Removed
The appeals do not stay the state court proceedings.
Removed
On April 18, 2023, the District Court entered an order denying the defendants' motion for reconsideration of the District Court order to remand and granted the defendants' motion to stay the judgment remanding the matters to state court, pending resolution of the defendants' lawsuit in the Fifth Circuit.
Removed
On May 4, 2023, the District Court denied the plaintiffs' motion to lift stay pending appeal. In May 2023, the Fifth Circuit entered an order granting the defendants' motion to stay further proceedings pending resolution of a related appeal between Plaquemines Parish and BP America Production Co., among others, which the Fifth Circuit designated as the lead appeal.
Removed
In the lead appeal proceedings, in May 2024, the Fifth Circuit affirmed the lower courts’ orders and remanded the cases to state court.
Removed
Following denial of the defendants' petition for rehearing on November 25, 2024, the Fifth Circuit stayed further proceedings pending resolution of the petition for writ of certiorari in a related appeal, which was filed with the Supreme Court of the United States in February 2025.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

1 edited+0 added−0 removed0 unchanged
Biggest changeItem 4. Mine Safety Disclosures 57 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities 58 Item 6. [Reserved] 59 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 60 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 77 Item 8.
Biggest changeItem 4. Mine Safety Disclosures 45 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities 46 Item 6. [Reserved] 47 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 48 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 64 Item 8.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

6 edited+2 added−4 removed3 unchanged
Biggest changeSecurity Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding securities authorized for issuance under equity compensation plans. Purchases of Equity Securities by the Issuer and Affiliated Purchasers Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits.
Biggest changeSecurity Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding securities authorized for issuance under equity compensation plans.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuers Purchases of Equity Securities Market for Common Stock Our common stock is listed on the NYSE under the symbol “TALO”. Holders of Record Pursuant to the records of our transfer agent, as of February 19, 2025, there were approximately 209 holders of record of our common stock.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuers Purchases of Equity Securities Market for Common Stock Our common stock is listed on the NYSE under the symbol “TALO”. Holders of Record Pursuant to the records of our transfer agent, as of February 17, 2026, there were approximately 133 holders of record of our common stock.
Exploration & Production Index $ 100 $ 68 $ 119 $ 189 $ 196 $ 194 The performance graph and the information contained in this section is not “soliciting material,” is being “furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing.
Exploration & Production Index $ 100 $ 176 $ 280 $ 291 $ 288 $ 295 The performance graph and the information contained in this section is not “soliciting material,” is being “furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing.
Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future.
Accordingly, we do not anticipate paying any cash dividends on our common stock in the near-term.
The graph compares the change in the cumulative total return of our common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for December 31, 2019 through December 31, 2024.
This historic stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the cumulative total return of our common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for December 31, 2020 through December 31, 2025.
The graph assumes that $100 was invested in our common stock and each index on December 31, 2019 and that dividends were reinvested. 2019 2020 2021 2022 2023 2024 Talos Energy Inc. $ 100 $ 27 $ 33 $ 63 $ 47 $ 32 S&P 500 Index $ 100 $ 118 $ 152 $ 125 $ 158 $ 197 Dow Jones U.S.
The graph assumes that $100 was invested in our common stock and each index on December 31, 2020 and that dividends were reinvested. 2020 2021 2022 2023 2024 2025 Talos Energy Inc. $ 100 $ 119 $ 229 $ 173 $ 118 $ 134 S&P 500 Index $ 100 $ 129 $ 105 $ 133 $ 166 $ 196 Dow Jones U.S.
Removed
On July 22, 2024, our Board authorized an additional $150.0 million of our previously approved limit increasing the amount remaining under our authorized plan to $159.6 million. As of December 31, 2024, there was approximately $157.4 million remaining under the authorized program.
Added
Purchases of Equity Securities by the Issuer and Affiliated Purchasers The following table sets forth information with respect to our repurchase of shares of common stock during the three months ended December 31, 2025 (in thousands, except for the share and per share amounts): Period Total Number of Shares Purchased Average Price Paid Total Number of Shares Purchased as Part of Publicly Announced Program (1) Approximate Dollar Values of Shares that May Yet be Purchased Under the Program October 1, 2025- October 31, 2025 — $ — — $ 97,330 November 1, 2025- November 30, 2025 159,571 $ 10.97 159,571 $ 95,580 December 1, 2025- December 31, 2025 1,330,000 $ 11.05 1,330,000 $ 80,889 Total 1,489,571 $ 11.04 1,489,571 (1) Refer to Part I, Item 7.
Removed
Repurchases may be made from time to time in the open market, in a privately negotiated transaction, or by such other means as will comply with applicable state and federal securities laws. All repurchased shares are held in treasury. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations.
Added
“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information regarding our authorized share repurchase program. 46 Table of Contents Stockholder Return Performance Presentation The following graph is included in accordance with the SEC’s executive compensation disclosure rules.
Removed
The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.
Removed
There were no shares of common stock repurchased during the three months ended December 31, 2024. 58 Table of Contents Stockholder Return Performance Presentation The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

98 edited+87 added−98 removed70 unchanged
Biggest changeCash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. 67 Table of Contents Results of Operations Revenues The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands, except per unit data): Year Ended December 31, 2024 2023 Change Revenues: Oil $ 1,806,148 $ 1,357,732 $ 448,416 Natural gas 105,528 68,034 37,494 NGL 61,892 32,120 29,772 Total revenues $ 1,973,568 $ 1,457,886 $ 515,682 Production Volumes: Oil (MBbls) 24,078 18,062 6,016 Natural gas (MMcf) 41,078 26,194 14,884 NGL (MBbls) 2,969 1,767 1,202 Total production volume (MBoe) 33,893 24,195 9,698 Daily Production Volumes by Product: Oil (MBblpd) 65.8 49.5 16.3 Natural gas (MMcfpd) 112.2 71.8 40.4 NGL (MBblpd) 8.1 4.8 3.3 Total production volume (MBoepd) 92.6 66.3 26.3 Average Sale Price per Unit: Oil (per Bbl) $ 75.01 $ 75.17 $ (0.16 ) Natural gas (per Mcf) $ 2.57 $ 2.60 $ (0.03 ) NGL (per Bbl) $ 20.85 $ 18.18 $ 2.67 Price per Boe $ 58.23 $ 60.26 $ (2.03 ) Price per Boe (including realized commodity derivatives) $ 58.37 $ 59.86 $ (1.49 ) The information below provides an analysis of the change in our oil, natural gas and NGL revenues in our Upstream Segment, due to changes in sales prices and production volumes (in thousands): Price Volume Total Revenues: Oil $ (3,807 ) $ 452,223 $ 448,416 Natural gas (1,204 ) 38,698 37,494 NGL 7,920 21,852 29,772 Total revenues $ 2,909 $ 512,773 $ 515,682 Volumetric Analysis — Production volumes increased by 26.3 MBoepd to 92.6 MBoepd for the year ended December 31, 2024.
Biggest changeResults of Operations Revenues The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands, except per unit data): Year Ended December 31, 2025 2024 Change Revenues: Oil $ 1,560,401 $ 1,806,148 $ (245,747 ) Natural gas 169,445 105,528 63,917 NGL 50,224 61,892 (11,668 ) Total revenues $ 1,780,070 $ 1,973,568 $ (193,498 ) Production Volumes: Oil (MBbls) 24,065 24,078 (13 ) Natural gas (MMcf) 46,122 41,078 5,044 NGL (MBbls) 2,782 2,969 (187 ) Total production volume (MBoe) 34,534 33,893 641 Daily Production Volumes by Product: Oil (MBblpd) 65.9 65.8 0.1 Natural gas (MMcfpd) 126.4 112.2 14.2 NGL (MBblpd) 7.6 8.1 (0.5 ) Total production volume (MBoepd) 94.6 92.6 2.0 Average Sale Price per Unit: Oil (per Bbl) $ 64.84 $ 75.01 $ (10.17 ) Natural gas (per Mcf) $ 3.67 $ 2.57 $ 1.10 NGL (per Bbl) $ 18.05 $ 20.85 $ (2.80 ) Price per Boe $ 51.55 $ 58.23 $ (6.68 ) Price per Boe (including realized commodity derivatives) $ 53.90 $ 58.37 $ (4.47 ) The information below provides an analysis of the change in our oil, natural gas and NGL revenues in our Upstream Segment, due to changes in sales prices and production volumes (in thousands): Price Volume Total Revenues: Oil $ (244,772 ) $ (975 ) $ (245,747 ) Natural gas 50,954 12,963 63,917 NGL (7,769 ) (3,899 ) (11,668 ) Total revenues $ (201,587 ) $ 8,089 $ (193,498 ) 55 Table of Contents Volumetric Analysis — Production volumes increased by 2.0 MBoepd to 94.6 MBoepd for the year ended December 31, 2025.
Exhibits and Financial Statement Schedules — Note 8 — Debt . Redemption of the 12.00% Second-Priority Senior Secured Notes—due January 2026 — On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 12.00% Notes, see Part IV, Item 15.
Redemption of the 12.00% Second-Priority Senior Secured Notes—due January 2026 — On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt .
However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control.
However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under our bank credit facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control.
Furthermore, the Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects.
The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects.
Interest Expense — We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Bank Credit Facility and term-based debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.
Interest Expense — We may finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our bank credit facility and term-based debt. As a result, we may incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.
As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do.
As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and may not adjust downward as fast as oil prices do.
Exhibits and Financial Statement Schedules — Note 3 — Acquisition and Divestitures and Note 11 — Employee Benefits Plans and Share-Based Compensation . Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance.
Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures and Note 11 — Employee Benefits Plans and Share-Based Compensation . Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance.
Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. 72 Table of Contents We fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary.
Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. 59 Table of Contents We fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the bank credit facility, if necessary.
The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. 76 Table of Contents The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows.
The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. 63 Table of Contents The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows.
Factors Affecting the Comparability of our Financial Condition and Results of Operations The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations. QuarterNorth Acquisition — On March 4, 2024, we completed the acquisition of QuarterNorth.
Factors Affecting the Comparability of our Financial Condition and Results of Operations The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations. QuarterNorth Acquisition — On March 4, 2024, we completed the acquisition of QuarterNorth Energy Inc.
The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1. 74 Table of Contents Material Cash Requirements — We are party to various contractual obligations.
The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1. 61 Table of Contents Material Cash Requirements — We are party to various contractual obligations.
This section of this Annual Report generally discusses 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 that are not included in this Annual Report can be found in “Part II, Item 7.
This section of this Annual Report generally discusses 2025 and 2024 items and year-to-year comparisons between 2025 and 2024. Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 that are not included in this Annual Report can be found in “Part II, Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 29, 2024. Our Business We are a technically driven, innovative, independent energy company focused on maximizing long-term value through our Upstream business in the U.S.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on February 27, 2025. Our Business We are a technically driven, innovative, independent energy company focused on maximizing long-term value through our Upstream business in the U.S.
Performance Obligations — As of December 31, 2024, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $42.4 million.
Performance Obligations — As of December 31, 2025, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $97.4 million.
EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.
EBITDA, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc. have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.
See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date.
Business and Properties—Summary of Reserves for further discussion. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date.
Overview of Debt Instruments Financing Arrangements — As of December 31, 2024, total debt, net of discount and deferred financing costs, was approximately $1,221.4 million, comprised of our $1,250.0 million aggregate principal amount of the 9.000% Notes and 9.375% Notes (as defined herein) and no outstanding borrowings under our Bank Credit Facility.
Overview of Debt Instruments Financing Arrangements — As of December 31, 2025, total debt, net of discount and deferred financing costs, was approximately $1,226.2 million, comprised of our $1,250.0 million aggregate principal amount of the 9.000% Notes and 9.375% Notes (as defined herein) and no outstanding borrowings under our Bank Credit Facility.
For the year ended December 31, 2024, the amount includes a gain of $100.4 million related to the TLCS Divestiture and a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the 2023 Mexico Divestiture.
For the year ended December 31, 2024, the amount includes a gain of $100.4 million related to the TLCS Divestiture and a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition.
Our hedging strategy and future hedging transactions will be determined in accordance with both our Bank Credit Facility and Hedging Policy and may be different from what we have done on a historical basis.
Our hedging strategy and future hedging transactions will be determined in accordance with both our A&R Credit Agreement and Hedging Policy and may be different from what we have done on a historical basis.
After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 1.2 MBoepd for the year ended December 31, 2024 based on production rates prior to the shut in.
During the year ended December 31, 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 1.2 MBoepd for the year ended December 31, 2024 based on production rates prior to the shut in.
Supplemental Non-GAAP Measure EBITDA and Adjusted EBITDA “EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future.
“EBITDA,” “Adjusted EBITDA,” and “Adjusted EBITDA attributable to Talos Energy Inc.” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future.
If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties. Income Taxes — Our provision for income taxes includes U.S. state and federal and foreign taxes.
If the Company incurs decommissioning costs in an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties. Income Taxes — Our provision for income taxes includes U.S. federal and state and non-U.S. taxes.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information. EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of America (the “EnVen Acquisition”). See Part IV, Item 15.
(“QuarterNorth”), a privately held U.S. Gulf of America exploration and production company (the “QuarterNorth Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information. EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S.
We were in compliance with all debt covenants at December 31, 2024. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt . Bank Credit Facility – matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions.
We were in compliance with all debt covenants at December 31, 2025. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt . Bank Credit Facility — We maintained a Bank Credit Facility with a syndicate of financial institutions.
Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact. We have historically focused our operations in the U.S.
Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact.
Exhibits and Financial Statement Schedules — Note 11 — Employee Benefits Plans and Share-Based Compensation . Transaction expenses include $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Part IV, Item 15.
Exhibits and Financial Statement Schedules — Note 11 — Employee Benefits Plans and Share-Based Compensation . Transaction expenses include $40.4 million in costs related to the EnVen Acquisition, inclusive of $25.3 million for the year ended December 31, 2023. See further discussion in Part IV, Item 15.
Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our 2025 Upstream capital spending program of $500.0 million to $540.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $120.0 million.
Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under our bank credit facility, provide sufficient liquidity to fund our 2026 capital spending program of $500.0 million to $550.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $130.0 million.
Exhibits and Financial Statement Schedules — Note 8 — Debt . Redemption of the 11.75% Senior Secured Second Lien Notes—due April 2026 — On February 7, 2024, we redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 11.75% Notes, see Part IV, Item 15.
Redemption of the 11.75% Senior Secured Second Lien Notes—due April 2026 — On February 7, 2024, we redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 11.75% Notes, see Part IV, Item 15.
Additionally, we are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See Part I, Item 3. Legal Proceedings for additional information.
We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See Part I, Item 3. Legal Proceedings for additional information.
Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. 70 Table of Contents Income Tax Benefit (Expense) — During the year ended December 31, 2024, we recorded $5.0 million of income tax expense compared to $60.6 million of income tax benefit during the year ended December 31, 2023.
Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. 57 Table of Contents Income Tax Benefit (Expense) — During the year ended December 31, 2025, we recorded $109.2 million of income tax benefit compared to $5.0 million of income tax expense during the year ended December 31, 2024.
We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines established by the SEC.
Our proved oil, natural gas and NGL reserves are estimated in accordance with the guidelines established by the SEC.
If the proved reserves used had been a 10 percent lower, depreciation, depletion and amortization in the year ended December 31, 2024 would have increased by an estimated $108.1 million.
If the proved reserves used had been 10 percent lower, depreciation, depletion and amortization in the year ended December 31, 2025 would have increased by an estimated $110.8 million.
In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Part I, Item 3. Legal Proceedings for additional information.
In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Part I, Item 3. Legal Proceedings for additional information. Supplemental Non-GAAP Measure EBITDA, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc.
Year Ended December 31, 2024 2023 2022 Oil: NYMEX WTI high per Bbl $ 85.35 $ 89.43 $ 114.84 NYMEX WTI low per Bbl $ 69.95 $ 70.25 $ 76.44 Average NYMEX WTI per Bbl $ 76.54 $ 77.63 $ 94.79 Average oil sales price per Bbl (including commodity derivatives) $ 75.07 $ 73.59 $ 68.40 Average oil sales price per Bbl (excluding commodity derivatives) $ 75.01 $ 75.17 $ 93.75 Natural Gas: NYMEX Henry Hub high per MMBtu $ 3.18 $ 3.27 $ 8.81 NYMEX Henry Hub low per MMBtu $ 1.49 $ 2.14 $ 4.38 Average NYMEX Henry Hub per MMBtu $ 2.19 $ 2.54 $ 6.42 Average natural gas sales price per Mcf (including commodity derivatives) $ 2.65 $ 3.32 $ 5.30 Average natural gas sales price per Mcf (excluding commodity derivatives) $ 2.57 $ 2.60 $ 7.06 NGLs: NGL realized price as a % of average NYMEX WTI 27 % 23 % 35 % To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, we enter into commodity derivative arrangements for a portion of our anticipated production.
Year Ended December 31, 2025 2024 2023 Oil: NYMEX WTI high per Bbl $ 75.74 $ 85.35 $ 89.43 NYMEX WTI low per Bbl $ 57.97 $ 69.95 $ 70.25 Average NYMEX WTI per Bbl $ 65.45 $ 76.54 $ 77.63 Average oil sales price per Bbl (including commodity derivatives) $ 68.18 $ 75.07 $ 73.59 Average oil sales price per Bbl (excluding commodity derivatives) $ 64.84 $ 75.01 $ 75.17 Natural Gas: NYMEX Henry Hub high per MMBtu $ 4.26 $ 3.18 $ 3.27 NYMEX Henry Hub low per MMBtu $ 2.91 $ 1.49 $ 2.14 Average NYMEX Henry Hub per MMBtu $ 3.53 $ 2.19 $ 2.54 Average natural gas sales price per Mcf (including commodity derivatives) $ 3.70 $ 2.65 $ 3.32 Average natural gas sales price per Mcf (excluding commodity derivatives) $ 3.67 $ 2.57 $ 2.60 NGLs: NGL realized price as a % of average NYMEX WTI 28 % 27 % 23 % To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, we enter into commodity derivative arrangements for a portion of our anticipated production.
We use the full cost method of accounting for oil and natural gas activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion. Accretion Expense — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure.
Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion. Accretion Expense — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure.
If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2024 and ending December 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $67.95 per Bbl of oil, $2.23 per Mcf of natural gas and $19.79 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $420.0 million.
If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2025 and ending December 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $58.76 per Bbl of oil, $3.26 per Mcf of natural gas and $17.35 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $807 million.
See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures . The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the years ended December 31, 2023 and 2022, respectively.
The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million for the year ended December 31, 2023. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments .
The information below provides the financial results and an analysis of significant variances in these results (in thousands): Year Ended December 31, 2024 2023 Depreciation, depletion and amortization $ 1,023,558 $ 663,534 Depreciation, depletion and amortization expense for the year ended December 31, 2024 increased by approximately $360.0 million, or 54%.
The information below provides the financial results and an analysis of significant variances in these results (in thousands): Year Ended December 31, 2025 2024 Depreciation, depletion and amortization $ 1,056,281 $ 1,023,558 Depreciation, depletion and amortization expense for the year ended December 31, 2025 increased by approximately $32.7 million, or 3%.
We define these as the following: • EBITDA — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense. • Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense. 71 Table of Contents The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands): Year Ended December 31, 2024 2023 2022 Net income (loss) $ (76,393 ) $ 187,332 $ 381,915 Interest expense 187,638 173,145 125,498 Income tax expense (benefit) 5,003 (60,597 ) 2,537 Depreciation, depletion and amortization 1,023,558 663,534 414,630 Accretion expense 117,604 86,152 55,995 EBITDA 1,257,410 1,049,566 980,575 Transaction and other (income) expense (1) (59,022 ) (33,295 ) (34,513 ) Decommissioning obligations (2) 8,559 11,879 31,558 Derivative fair value (gain) loss (3) 1,458 (80,928 ) 272,191 Net cash received (paid) on settled derivative instruments (3) 4,710 (9,457 ) (425,559 ) (Gain) loss on debt extinguishment 60,256 — 1,569 Non-cash equity-based compensation expense 14,462 12,953 15,953 Adjusted EBITDA $ 1,287,833 $ 950,718 $ 841,774 (1) For the year ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer as discussed in Part IV, Item 15.
We define these as the following: • EBITDA — Net income (loss) attributable to Talos Energy Inc. plus net income (loss) attributable to noncontrolling interest, plus interest expense, income tax benefit (expense), depreciation, depletion and amortization, and accretion expense. • Adjusted EBITDA — EBITDA plus non-cash impairment of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash impairment of other well equipment and non-cash equity-based compensation expense. • Adjusted EBITDA attributable to Talos Energy Inc. — Adjusted EBITDA, less adjustments for noncontrolling interest. 58 Table of Contents The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands): Year Ended December 31, 2025 2024 2023 Net income (loss) attributable to Talos Energy Inc. $ (494,290 ) $ (76,393 ) $ 187,332 Net income (loss) attributable to noncontrolling interest (1,034 ) — — Net income (loss) (495,324 ) (76,393 ) 187,332 Interest expense 163,381 187,638 173,145 Income tax (benefit) expense (109,169 ) 5,003 (60,597 ) Depreciation, depletion and amortization 1,056,281 1,023,558 663,534 Accretion expense 125,296 117,604 86,152 EBITDA 740,465 1,257,410 1,049,566 Impairment of oil and natural gas properties 454,482 — — Transaction and other (income) expense (1) 5,001 (59,022 ) (33,295 ) Decommissioning obligations (2) 3,245 8,559 11,879 Derivative fair value (gain) loss (3) (105,455 ) 1,458 (80,928 ) Net cash received (paid) on settled derivative instruments (3) 81,471 4,710 (9,457 ) (Gain) loss on debt extinguishment — 60,256 — Non-cash equity-based compensation expense 18,418 14,462 12,953 Adjusted EBITDA $ 1,197,627 $ 1,287,833 $ 950,718 (1) For the year ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer as discussed in Part IV, Item 15.
The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials.
The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials.
If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. During 2024, 2023 and 2022 our ceiling test computations for our U.S. oil and gas properties did not result in a write down.
If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. During 2025, our ceiling test calculations resulted in an impairment of our oil and natural gas properties of $454.5 million. During 2024 and 2023 our ceiling test computations for our U.S. oil and gas properties did not result in an impairment.
In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods indicated.
Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices. 53 Table of Contents In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods indicated.
The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data): Year Ended December 31, 2024 2023 Lease operating expenses $ 566,041 $ 389,621 Lease operating expenses per Boe $ 16.70 $ 16.10 Total lease operating expenses for the year ended December 31, 2024 increased by approximately $176.4 million, or 45%.
The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data): Year Ended December 31, 2025 2024 Lease operating expenses $ 546,716 $ 566,041 Lease operating expenses per Boe $ 15.83 $ 16.70 Total lease operating expenses for the year ended December 31, 2025 decreased by approximately $19.3 million, or 3%.
Prices are determined using SEC pricing. 75 Table of Contents Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. Our reserves at December 31, 2024 were fully engineered by NSAI, while prior year reserve estimates, including as of December 31, 2023 and 2022, were audited by NSAI.
Prices are determined using SEC pricing. 62 Table of Contents Estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. Our reserves at December 31, 2025 and 2024 were fully engineered by NSAI and audited by them at December 31, 2023. See Part I, Items 1 and 2.
The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data): Year Ended December 31, 2024 2023 Upstream Segment $ 191,063 $ 145,960 CCS Segment 10,454 12,533 Total general and administrative expense $ 201,517 $ 158,493 Upstream general and administrative expense per Boe $ 5.64 $ 6.03 General and administrative expense for the year ended December 31, 2024, increased by approximately $43.0 million, or 27%.
The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data): Year Ended December 31, 2025 2024 Upstream Segment $ 155,368 $ 191,063 CCS Segment — 10,454 Total general and administrative expense $ 155,368 $ 201,517 Upstream general and administrative expense per Boe $ 4.50 $ 5.64 General and administrative expense for the year ended December 31, 2025, decreased by approximately $46.1 million, or 23%.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments for additional information.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.
Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition.
Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information. Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million.
Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field. During the year ended December 31, 2024, Helix dry-docked the HP-I.
We produce the Phoenix Field through the Helix Producer I (“HP-I”) that is operated by Helix Energy Solutions Group, Inc (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field.
The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.
The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.
The information below provides the financial results and an analysis of significant variances in these results (in thousands): Year Ended December 31, 2024 2023 Accretion expense $ 117,604 $ 86,152 Other operating (income) expense $ (109,454 ) $ (52,155 ) Interest expense $ 187,638 $ 173,145 Price risk management activities (income) expense $ 1,458 $ (80,928 ) Equity method investment (income) expense $ 10,289 $ 3,209 Other (income) expense $ 44,930 $ (12,371 ) Income tax (benefit) expense $ 5,003 $ (60,597 ) Accretion Expense — During the year ended December 31, 2024, we recorded $117.6 million of accretion expense compared to $86.2 million during the year ended December 31, 2023.
The information below provides the financial results and an analysis of significant variances in these results (in thousands): Year Ended December 31, 2025 2024 Accretion expense $ 125,296 $ 117,604 Impairment of oil and natural gas properties $ 454,482 $ — Other operating (income) expense $ 1,789 $ (109,454 ) Interest expense $ 163,381 $ 187,638 Price risk management activities (income) expense $ (105,455 ) $ 1,458 Equity method investment (income) expense $ 1,807 $ 10,289 Other (income) expense $ (15,520 ) $ 44,930 Income tax (benefit) expense $ (109,169 ) $ 5,003 Accretion Expense — During the year ended December 31, 2025, we recorded $125.3 million of accretion expense compared to $117.6 million during the year ended December 31, 2024.
Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases and for general corporate purposes. The cost of borrowing under our Bank Credit Facility is influenced by changes in the federal funds rate. As interest rates increase, it becomes more expensive to borrow money while interest rate cuts make it less expensive to borrow money.
Our primary uses of cash are for capital expenditures, operating costs, working capital, debt service, share repurchases, future collateral payments and for general corporate purposes. The cost of borrowing under our bank credit facility is influenced by changes in the federal funds rate.
Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion. Other Operating (Income) Expense — During the year ended December 31, 2024, we recognized a gain of $100.4 million on the TLCS Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.
Other Operating (Income) Expense — During the year ended December 31, 2024, we recognized a gain of $100.4 million from the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.
The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demand. Per BOEM’s June 28, 2024 news release, BOEM indicated it may take up to 24 months from that date to complete the processing of financial assurance demands. The final rule was challenged in the U.S.
The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demand. The final rule was challenged in the U.S.
The change is primarily the result of the increase in accretion associated with the higher asset retirement obligations subject to accretion expense including $15.4 million of incremental accretion expense related to the asset retirement obligations assumed as part of the QuarterNorth Acquisition. See Part IV, Item 15.
The change is primarily the result of a $4.4 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition combined with a higher asset retirement obligation subject to accretion expense. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.
The following table presents a breakout of each revenue component: Year Ended December 31, 2024 2023 2022 Oil 92 % 93 % 83 % Natural gas 5 % 5 % 14 % NGL 3 % 2 % 3 % Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. 65 Table of Contents Realized Prices on the Sale of Oil, Natural Gas and NGLs — The NYMEX WTI prompt month oil settlement price is a widely used benchmark in the pricing of domestic oil in the United States.
The following table presents a breakout of each revenue component: Year Ended December 31, 2025 2024 2023 Oil 88 % 92 % 93 % Natural gas 10 % 5 % 5 % NGL 2 % 3 % 2 % Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
At December 31, 2024, the Company’s ceiling test computation was based on SEC pricing of $75.51 per Bbl of oil, $2.45 per Mcf of natural gas and $21.91 per Bbl of NGLs.
At December 31, 2025, the Company’s ceiling test computation was based on SEC pricing of $65.37 per Bbl of oil, $3.61 per Mcf of natural gas and $19.22 per Bbl of NGLs.
Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations.
The share repurchase program has no set term limits. All repurchased shares are held in treasury. Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws.
Production Taxes — Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana. 66 Table of Contents Depreciation, Depletion and Amortization expense — Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves.
Production Taxes — Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana.
See additional information on the valuation allowance as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Income Taxes . Commitments and Contingencies For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies .
Exhibits and Financial Statement Schedules — Note 12 — Income Taxes . Commitments and Contingencies For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies . Additionally, we are party to lawsuits arising in the ordinary course of our business.
Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2024 (in thousands): U.S. drilling & completions $ 283,779 Asset management (1) 109,222 Seismic and G&G, land, capitalized G&A and other 91,059 Total Upstream capital expenditures 484,060 Plugging & abandonment 108,789 Decommissioning obligations settled (2) 5,447 Investment in Mexico 5,469 Total Upstream 603,765 Investment in CCS 17,519 Total $ 621,284 (1) Asset management consists of capital expenditures for development related activities primarily associated with recompletions and improvements to our facilities and infrastructure.
Capital and Other Expenditures — The following is a table of our capital and other expenditures, excluding acquisitions, for the year ended December 31, 2025 (in thousands): U.S. drilling & completions $ 394,264 Asset management (1) 31,991 Seismic and G&G, land, capitalized G&A and other 67,812 Total capital expenditures 494,067 Plugging & abandonment 117,847 Decommissioning obligations settled (2) 1,102 Investment in Mexico 4,559 Total capital and other expenditures $ 617,575 (1) Asset management consists of capital expenditures for development related activities primarily associated with recompletions and improvements to our facilities and infrastructure.
To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.
To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness. Surety Agreements and Collateral Requirements — The CFSAs require us to post agreed upon amounts of collateral through July 1, 2031. See Part II, Item 7.
The income of $80.9 million for the year ended December 31, 2023 consisted of $90.4 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $9.5 million in cash settlement losses.
Price Risk Management Activities — The income of $105.5 million for the year ended December 31, 2025 consisted of $81.5 million in cash settlement gains and $24.0 million in non-cash gains from the increase in the fair value of our open derivative contracts.
The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that we deliver to the administrative agent of our Bank Credit Facility. For additional details on our Bank Credit Facility, see Part IV, Item 15.
The borrowing base was redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that we delivered to the administrative agent of our Bank Credit Facility. As discussed above under “— Recent Developments,” the A&R Credit Agreement replaced the Bank Credit Facility in January 2026.
The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to P&A and decommission the associated assets.
The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to plug, remove or abandon the associated assets.
The tightened capacity in the surety market may impact our ability to secure surety bonds at commercially reasonable terms and therefore, our ability to enter into such joint participation or asset acquisition opportunities may be impacted.
The tightened capacity in the surety market may impact our ability to secure surety bonds at commercially reasonable terms and therefore, our ability to enter into such joint participation or asset acquisition opportunities may be impacted. 51 Table of Contents 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.
Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2024. 62 Table of Contents The EIA published its February 2025 Short-Term Energy Outlook on February 11, 2025.
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.
General and Administrative Expense — General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance.
Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. 54 Table of Contents General and Administrative Expense — General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance.
Investing Activities — Net cash used in investing activities increased $807.7 million in 2024 compared to 2023 primarily due to cash paid for acquisitions of $936.2 million, net of cash acquired, of which $916.0 million related to the QuarterNorth Acquisition.
Investing Activities — Net cash used in investing activities decreased $773.5 million in 2025 compared to 2024. Payments for acquisitions (net of cash acquired) decreased by $886.2 million. During the year ended December 31, 2024, payment for acquisitions was $936.2 million, of which $916.0 million related to the QuarterNorth Acquisition.
The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt for additional information.
During the year ended December 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,217.1 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part IV, Item 15.
Inflation may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. In 2022 and 2023, the Fed raised its benchmark interest rate 11 times.
Inflation may also result in increases in the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. 50 Table of Contents 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%.
Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information. Planned Downtime — We are vulnerable to downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the Helix Producer I (“HP-I”) that is operated by Helix Energy Solutions Group, Inc (“Helix”).
Gulf of America (the “EnVen Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information. Planned Downtime — We are vulnerable to downtime events impacting the transportation, gathering and processing of production.
For the year ended December 31, 2023, we recorded $106.8 million of income tax benefit related to the release of the valuation allowance for our federal deferred tax assets partially offset with an income tax expense of $31.1 million related to current year activity inclusive of permanent differences.
The benefit of $109.2 million for the year ended December 31, 2025 is primarily due to current year activity offset with income tax expense of $28.8 million related to recording a valuation allowance on its U.S. federal deferred tax assets.
The IRA 2022 provides for, among other things, the imposition of a 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations such as us after December 31, 2022. Accordingly, the excise tax applies to our share repurchase program. The excise tax payment is non-deductible for income tax purposes.
Our share repurchase program is subject to the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations.
Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures . General and Administrative Expense The following table highlights general and administrative expense items in total and on a cost per Boe production basis for the Upstream Segment.
This increase was primarily driven by increased production volumes of 2.0 MBoepd discussed above. General and Administrative Expense The following table highlights general and administrative expense items in total and on a cost per Boe production basis for the Upstream Segment.
Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments .
For the year ended December 31, 2023, the amount includes a $66.2 million gain on the 2023 Mexico Divestiture related to a 49.9% equity interest in Talos Mexico sold to Zamajal. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures .
Moreover, regardless of the final rule, BOEM has the right to issue financial assurance orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning liabilities. See Part I, Items 1 and 2.
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. See Part I, Items 1 and 2.
This increase was primarily related to the Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $43.6 million or $1.29 per Boe. The CCS Segment reflects an increase in transaction costs and severance costs of $7.9 million related to the TLCS Divestiture.
This decrease was primarily driven by Upstream Segment transactions costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $46.6 million or $2.65 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.0 million due to the divestiture of our CCS business.
District Court for the Western District of Louisiana by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. The implementation of the final rule is not currently stayed and the outcome of these challenges remains uncertain.
District Court for the Western District of Louisiana (the “Western Louisiana District Court”) by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. The Western Louisiana District Court granted a stay of the litigation while BOEM pursues efforts to suspend, revise, or rescind the final rule.
The next dry-dock is scheduled for the first half of 2027 with a projected shut-in period of approximately 45 days. Known Trends and Uncertainties Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand.
The next dry-dock is scheduled for the first half of 2027 with a projected shut-in period of approximately 45 days.
The increase was primarily due to 21.9 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 2.2 MBoepd from the EnVen Acquisition that closed mid-first quarter of 2023.
The increase was primarily due to 6.4 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there were increases of 2.3 MBoepd and 1.2 MBoepd of production from our Katmai West #2 and Sunspear wells, respectively, both of which commenced initial production in June 2025.

… 203 more changes not shown on this page.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

13 edited+0 added−0 removed2 unchanged
Biggest changeWe are subject to the risk of changes in interest rates under our Bank Credit Facility. In addition, the terms of our Bank Credit Facility require us to pay higher interest rates as we utilize a larger percentage of our available borrowing base.
Biggest changeIn addition, the terms of our A&R Credit Agreement require us to pay higher interest rates as we utilize a larger percentage of our available borrowing base.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk We are currently exposed to market risk in two areas: commodity prices and, to a lesser extent, interest rate risk. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of market price risk exposures primarily related to our oil and natural gas production.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk We are primarily exposed to market risk in two areas: commodity prices and, to a lesser extent, interest rate risk. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of market price risk exposures primarily related to our oil and natural gas production.
Variable Interest Rate Risks We had total debt outstanding of $1,250.0 million at December 31, 2024, before unamortized original issue discount and deferred financing costs from our 9.000% Notes and 9.375% Notes, which bears interest at a fixed rate. There were no outstanding borrowings under our Bank Credit Facility with variable interest rates.
Variable Interest Rate Risks We had total debt outstanding of $1,250.0 million at December 31, 2025, before unamortized original issue discount and deferred financing costs from our 9.000% Notes and 9.375% Notes, which bears interest at a fixed rate. There were no outstanding borrowings under our Bank Credit Facility with variable interest rates.
We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. As of December 31, 2024, our interest rate risk exposure is mitigated as a result of fixed interest rates on 100% of our debt.
We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. As of December 31, 2025, our interest rate risk exposure is mitigated as a result of fixed interest rates on 100% of our debt.
For any quarter occurring during the first four forward fiscal quarters, we are required to hedge a minimum of 50% of our reasonably anticipated projected production from proved developed producing reserves from the semi-annual reserves report delivered to the administrative agent of our Bank Credit Facility, adjusted to 45% in July and November and 25% in August, September and October.
For any quarter occurring during the first four forward fiscal quarters, we are required to hedge a minimum of 50% of our reasonably anticipated projected production from proved developed producing reserves from the semi-annual reserves report delivered to the administrative agent of our A&R Credit Agreement, adjusted to 45% in July and November and 25% in August, September and October.
For the fifth and sixth forward fiscal quarters, if the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is greater than or equal to 1.00 to 1.00, then we are required to hedge a minimum of 25%, adjusted to 20% in August, September and October.
For the fifth and sixth forward fiscal quarters, if the Consolidated Total Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) is greater than or equal to 1.00 to 1.00, then we are required to hedge a minimum of 25%, adjusted to 20% in August, September and October.
Price Risk Management Activities We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production through the use of oil and natural gas swaps. These contracts will impact our earnings as the fair value of these derivatives changes.
Price Risk Management Activities Historically, we have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production primarily through the use of oil and natural gas swaps and costless collars. These contracts will impact our earnings as the fair value of these derivatives changes.
We are subject to a minimum hedging requirement under our Bank Credit Facility for each calendar month on a six-full fiscal quarter rolling basis.
We are subject to a minimum hedging requirement under our A&R Credit Agreement for each calendar month on a six-full fiscal quarter rolling basis.
Commodity Price Risks Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and cash flow. During year ended December 31, 2024, our average oil price realizations after the effect of derivatives increased 2% to $75.07 per Bbl from $73.59 per Bbl in the comparable 2023 period.
Commodity Price Risks Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and cash flow. During year ended December 31, 2025, our average oil price realizations after the effect of derivatives decreased 9% to $68.18 per Bbl from $75.07 per Bbl in the comparable 2024 period.
Our derivatives will not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production. 77 Table of Contents We had commodity derivative instruments in place to reduce the price risk associated with future production of 11,642 MBbls of crude oil and 28,245 MMBtu of natural gas at December 31, 2024, with a net derivative asset position of $23.7 million.
Our derivatives will not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production. 64 Table of Contents We had commodity derivative instruments in place to reduce the price risk associated with future production of 7,371 MBbls of crude oil and 10,465 MMBtu of natural gas at December 31, 2025, with a net derivative asset position of $47.7 million.
For additional information regarding the borrowing base utilization percentage associated with our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt , included elsewhere in this Annual Report.
For additional information regarding the borrowing base utilization percentage associated with our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt , included elsewhere in this Annual Report. We are subject to the risk of changes in interest rates under our bank credit facility.
Our average natural gas price realizations after the effect of derivatives decreased 20% during the year ended December 31, 2024 to $2.65 per Mcf from $3.32 per Mcf in the comparable 2023 period.
Our average natural gas price realizations after the effect of derivatives increased 40% during the year ended December 31, 2025 to $3.70 per Mcf from $2.65 per Mcf in the comparable 2024 period.
The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at December 31, 2024 (in thousands): Oil and Natural Gas Derivatives Ten Percent Increase Ten Percent Decrease Fair Value Fair Value Change Fair Value Change Price impact (1) $ 23,728 $ (61,501 ) $ (85,229 ) $ 109,219 $ 85,491 (1) Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in oil and natural gas prices.
The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at December 31, 2025 (in thousands): Oil and Natural Gas Derivatives Ten Percent Increase Ten Percent Decrease Fair Value Fair Value Change Fair Value Change Price impact (1) $ 47,712 $ 9,629 $ (38,083 ) $ 88,273 $ 40,561 (1) Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in oil and natural gas prices.

Other TALO 10-K year-over-year comparisons