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What changed in TALOS ENERGY INC.'s 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of TALOS ENERGY INC.'s 2023 and 2024 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 2024 report.

+508 added−483 removedSource: 10-K (2025-02-27) vs 10-K (2024-02-29)

Top changes in TALOS ENERGY INC.'s 2024 10-K

508 paragraphs added · 483 removed · 294 edited across 7 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

141 edited+113 added−109 removed156 unchanged
Biggest changeRussia’s recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsequent military action against Ukraine have led to an unprecedented expansion of sanction programs imposed by the U.S., the European Union, the United Kingdom, Canada, Switzerland, Japan and other countries against Russia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic and the so-called Luhansk People’s Republic, including, among others: • blocking sanctions against some of the largest state-owned and private Russian financial institutions (and their subsequent removal from the Society for Worldwide Interbank Financial Telecommunication payment system) and certain Russian businesses, some of which have significant financial and trade ties to the European Union; • blocking sanctions against Russian and Belarusian individuals, including the Russian President, other politicians and those with government connections or involved in Russian military activities; and • blocking of Russia’s foreign currency reserves as well as expansion of sectoral sanctions and export and trade restrictions, limitations on investments and access to capital markets and bans on various Russian imports. 40 Table of Contents In retaliation against new international sanctions and as part of measures to stabilize and support the volatile Russian financial and currency markets, the Russian authorities also imposed significant currency control measures aimed at restricting the outflow of foreign currency and capital from Russia, imposed various restrictions on transacting with non-Russian parties, banned exports of various products and other economic and financial restrictions.
Biggest changeWe expect the ongoing war to prolong disruptions in the region. 32 Table of Contents Russia’s recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsequent military action against Ukraine have led to an unprecedented expansion of sanction programs imposed by the U.S., the European Union, the United Kingdom, Canada, Switzerland, Japan and other countries against Russia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic and the so-called Luhansk People’s Republic, including, among others: • blocking sanctions against some of the largest state-owned and private Russian financial institutions (and their subsequent removal from the Society for Worldwide Interbank Financial Telecommunication payment system) and certain Russian businesses, some of which have significant financial and trade ties to the European Union; • blocking sanctions against Russian and Belarusian individuals, including the Russian President, other politicians and those with government connections or involved in Russian military activities; and • blocking of Russia’s foreign currency reserves as well as expansion of sectoral sanctions and export and trade restrictions, limitations on investments and access to capital markets and bans on various Russian imports.
Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” (i.e., misleading information or false claims overstating potential ESG benefits).
Furthermore, public statements with respect to ESG-related matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” (i.e., misleading information or false claims overstating potential ESG benefits).
As such, the success and profitability of our operations may be disproportionately exposed to the effect of regional conditions such as: • severe weather, such as hurricanes, winter storms, loop currents, tornadoes and other adverse climatic conditions; • changes in state or regional laws and regulations affecting our operations (including regulations that may, in certain circumstances, impose strict liability for pollution damage or require posting substantial bonds to address decommissioning and P&A costs) and interruption or termination of operations by governmental authorities based on environmental, safety or other considerations; • local price fluctuations and other regional supply and demand factors, including availability of gathering, pipeline, transportation and storage capacity constraints; • production delays or decreases in the region; 34 Table of Contents • limited potential customers; • infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor; • changes in the status of pipelines that we depend on for transportation of our production to the marketplace; • changes in guidelines issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS; and/or • changes imposed as a result of litigation or by a new presidential administration or by Congress in the United States that may result in added restrictions and delays or prohibitions in offshore oil and natural gas exploration and production activities, including with respect to leasing, permitting, site development or operation in federal waters or hydraulic fracturing.
As such, the success and profitability of our operations may be disproportionately exposed to the effect of regional conditions such as: • severe weather, such as hurricanes, winter storms, loop currents, tornadoes and other adverse climatic conditions; • changes in state or regional laws and regulations affecting our operations (including regulations that may, in certain circumstances, impose strict liability for pollution damage or require posting substantial bonds to address decommissioning and P&A costs) and interruption or termination of operations by governmental authorities based on environmental, safety or other considerations; 31 Table of Contents • local price fluctuations and other regional supply and demand factors, including availability of gathering, pipeline, transportation and storage capacity constraints; • production delays or decreases in the region; • limited potential customers; • infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor; • changes in the status of pipelines that we depend on for transportation of our production to the marketplace; • changes in guidelines issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS; and/or • changes imposed as a result of litigation or by a new presidential administration or by Congress in the United States that may result in added restrictions and delays or prohibitions in offshore oil and natural gas exploration and production activities, including with respect to leasing, permitting, site development or operation in federal waters or hydraulic fracturing.
Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the Bank Credit Facility, the indentures for each of Talos Production Inc.’s (the “Issuer”) 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) and 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes,” and together, with the 9.000% Notes, our “New Senior Notes”), have important consequences on our operations, including: • requiring that we dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures, and other general business activities; • limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities; • limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; • detracting from our ability to successfully withstand a downturn in our business or the economy generally; • placing us at a competitive disadvantage against other less leveraged competitors; and • making us vulnerable to increases in interest rates because debt under our Bank Credit Facility is at variable rates.
Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the Bank Credit Facility, the indentures for each of Talos Production Inc.’s (the “Issuer”) 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) and 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes,” and together, with the 9.000% Notes, our “Senior Notes”), have important consequences on our operations, including: • requiring that we dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures, and other general business activities; • limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities; • limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; • detracting from our ability to successfully withstand a downturn in our business or the economy generally; • placing us at a competitive disadvantage against other less leveraged competitors; and • making us vulnerable to increases in interest rates because debt under our Bank Credit Facility is at variable rates.
As a result, our reserve replacement needs from new prospects may be greater than those of other companies with longer-life reserves in other producing areas. Our future oil and natural gas production is highly dependent upon finding and/or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.
As a result, our reserve replacement needs from new prospects may be greater than those of other companies with longer-life reserves in other producing areas. Furthermore, our future oil and natural gas production is highly dependent upon finding and/or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.
For example, the IRA 2022 contains significant financial incentives for the development of renewable energy, alternative fuels, supporting infrastructure and carbon capture and sequestration and imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge generated from sources in the onshore petroleum and natural gas production categories.
For example, the IRA 2022 contains significant financial incentives for the development of renewable energy, alternative fuels, supporting infrastructure and carbon capture and sequestration and imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge generated from sources in the offshore and onshore petroleum and natural gas production categories.
Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our debt, including our Bank Credit Facility and the respective indentures for our New Senior Notes, may also prohibit us from taking such actions.
Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our debt, including our Bank Credit Facility and the respective indentures for our Senior Notes, may also prohibit us from taking such actions.
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 Mexico and in the shallow waters off the coast of Mexico.
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.
Alternatively, a cessation of hostilities as a result of a negotiated withdrawal or otherwise—particularly if coupled with an easing of international sanctions — could cause commodity prices to decline in a manner that would reduce the revenues we receive for our oil and gas production.
Alternatively, a cessation of hostilities as a result of a negotiated withdrawal or otherwise—particularly if coupled with an easing of international sanctions — could cause commodity prices to decline globally in a manner that would reduce the revenues we receive for our oil and gas production.
The marketability of our production depends upon the availability, proximity, operation and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of this infrastructure could result in the shut-in of producing wells or delays or discontinuance of development plans for our properties.
The marketability of our production depends upon the availability, proximity, operation and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity or closure of this infrastructure could result in the shut-in of producing wells or delays or discontinuance of development plans for our properties.
There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations.
There may be threatened, contemplated, asserted or other claims against the assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations.
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. 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 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.
These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others. 54 Table of Contents Our Second Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of Delaware and, to the extent enforceable, the federal district courts of the United States of America as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others. 52 Table of Contents Our Second Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of Delaware and, to the extent enforceable, the federal district courts of the United States of America as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Future collateral requirements for our commodity hedging activities are uncertain and depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions. O ur operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine life and endangered and threatened species.
Future collateral requirements for our commodity hedging activities are uncertain and depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions. Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine life and endangered and threatened species.
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 Mexico 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.
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.
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. 43 Table of Contents Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affect our operations.
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. 39 Table of Contents Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affect our operations.
Our Director of ESG is responsible for driving our sustainability initiatives, engaging with stakeholders, benchmarking our ESG data, and evaluating potential and emerging ESG drivers.
Our Director of Environmental and Sustainability is responsible for driving our sustainability initiatives, engaging with stakeholders, benchmarking our ESG data, and evaluating potential and emerging ESG drivers.
As a result, we may significantly increase or decrease our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions.
As a result, we may significantly increase or decrease our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of America, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions.
Gulf of Mexico where the purchasers, as assignees, typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations.
Gulf of America where the purchasers, as assignees, typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations.
Our Second Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our or our stockholders’ behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees, agents and stockholders to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our Second Amended and Restated Certificate of Incorporation or our Second Amended and Restated Bylaws, (iv) any action as to which the DGCL confers jurisdiction to the Court of Chancery of the State of Delaware, or (v) any other action asserting a claim that is governed by the internal affairs doctrine shall be the Court of Chancery of the State of Delaware.
Our Second Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our or our stockholders’ behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees, agents and stockholders to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (“DGCL”), our Second Amended and Restated Certificate of Incorporation or our Second Amended and Restated Bylaws, (iv) any action as to which the DGCL confers jurisdiction to the Court of Chancery of the State of Delaware, or (v) any other action asserting a claim that is governed by the internal affairs doctrine shall be the Court of Chancery of the State of Delaware.
As an oil and gas producer, we have various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts.
As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts.
Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance. 44 Table of Contents We reevaluate the purchase of insurance, policy limits and terms annually.
Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance. 40 Table of Contents We reevaluate the purchase of insurance, policy limits and terms annually.
Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs.
Gulf of America is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs.
We cannot predict with any certainty the full impact of any new laws or regulations on our drilling and production operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. See Part I, Items 1 and 2.
We cannot predict with any certainty the full impact of any new laws, legal proceedings or regulations on our drilling and production operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. See Part I, Items 1 and 2.
Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas. 50 Table of Contents We depend on our Bank Credit Facility for a portion of our future capital needs.
Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas. 48 Table of Contents We depend on our Bank Credit Facility for a portion of our future capital needs.
Business and Properties—Summary of Reserves for further discussion on 2023 changes in estimates of our proved reserves. You should not assume that any present value of future net cash flows from our proved reserves represents the market value of our estimated oil and natural gas reserves.
Business and Properties—Summary of Reserves for further discussion on 2024 changes in estimates of our proved reserves. You should not assume that any present value of future net cash flows from our proved reserves represents the market value of our estimated oil and natural gas reserves.
We base the estimated discounted future net cash flows from our proved reserves at December 31, 2023 on historical 12-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower.
We base the estimated discounted future net cash flows from our proved reserves at December 31, 2024 on historical 12-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower.
Moreover, while we endeavor to publish transparent sustainability reports, the voluntary disclosures therein are sometimes based on assumptions and calculations that may or may not be representative of actual or forecasted risks or events, including the costs associated therewith.
Moreover, while we endeavor to publish transparent sustainability reports, the voluntary disclosures therein are sometimes based on assumptions and calculations or hypothetical scenarios that may or may not be representative of actual or forecasted risks or events, including the costs associated therewith.
The operators of those properties may, depending on the terms of the applicable joint operating agreement: • refuse to initiate exploration or development projects; • initiate exploration or development projects on a slower or faster schedule than we would prefer; • delay the pace of exploratory drilling or development; and/or • drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.
The operators of those properties may, depending on the terms of the applicable joint operating agreement: • refuse to initiate exploration or development projects; • initiate exploration or development projects on a slower or faster schedule than we anticipate; • delay the pace of exploratory drilling or development; and/or • drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.
A significant increase in the wages paid by competing employers or the unionization of our U.S. Gulf of Mexico employees could result in a reduction of our labor force, increases in the wage rates that we will have to pay, or both.
A significant increase in the wages paid by competing employers or the unionization of our U.S. Gulf of America employees could result in a reduction of our labor force, increases in the wage rates that we will have to pay, or both.
The rule requires, among other things, that the blowout preventer system is able to close and seal the wellbore at all times to the wells maximum kick tolerance design limits and includes more stringent requirements for failure reporting.
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.
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; 35 Table of Contents • 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: • 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.
The global or national outbreak of an illness or other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees.
The global or national outbreak of an illness or other communicable disease, or any other public health crisis may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees.
On the acreage that we do not operate, we have less control over the timing of drilling, and therefore there is additional risk of expirations occurring in those acreages. The marketability of our production depends mostly upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities.
On the acreage that we do not operate, we have less control over the timing of drilling, and therefore there is additional risk of expirations occurring in those acreages. 34 Table of Contents The marketability of our production depends mostly upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities.
Exhibits and Financial Statement Schedules — Note 8 — Debt — Limitation on Restricted Payments Including Dividends for additional information. 52 Table of Contents Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our current and future financial position and results of operations.
Exhibits and Financial Statement Schedules — Note 8 — Debt — Limitation on Restricted Payments Including Dividends for additional information. Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our current and future financial position and results of operations.
The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. I nflationary issues and associated changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.
The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. Inflationary issues and associated changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.
For example, the ability of oil and gas companies to access the equity and high yield debt markets has been, and continues to be, significantly limited. We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc.
For example, the ability of oil and gas companies to access the equity and high yield debt markets has been, and continues to be, significantly limited. 50 Table of Contents We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc.
Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, and the risk that we are required to write-down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile.
In addition, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, and the risk that we are required to write-down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile.
The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time.
The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models to be determined by the lenders at such time.
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, 2023, approximately 53% of our net acreage was undeveloped acres. See Part I, Items 1 and 2. Business and Properties—Acreage for further discussion.
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.
These difficulties include, among other things: • operating a larger organization; • coordinating geographically disparate organizations, systems and facilities; • integrating corporate, technological and administrative functions; • diverting management’s attention from regular business concerns; • diverting financial resources away from existing operations; • increasing our indebtedness; and • incurring potential environmental or regulatory liabilities and title problems.
These difficulties include, among other things: • operating a larger organization; • coordinating geographically disparate organizations, systems and facilities; 51 Table of Contents • integrating corporate, technological and administrative functions; • diverting management’s attention from regular business concerns; • diverting financial resources away from existing operations; • increasing our indebtedness; and • incurring potential environmental or regulatory liabilities and title problems.
This could result in a current or future tax liability, which could adversely affect our financial condition and cash flows. 51 Table of Contents 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, 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.
Because of the lack and high cost of infrastructure, some reserve discoveries in the Deepwater may never be produced economically. 45 Table of Contents If any of these industry operating risks occur, we could have substantial losses.
Because of the lack and high cost of infrastructure, some reserve discoveries in the Deepwater may never be produced economically. If any of these industry operating risks occur, we could have substantial losses.
Such assumptions and calculations are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many environmental, social and governance (“ESG”) matters. 48 Table of Contents The Board’s SSCR Committee is the primary committee responsible for overseeing and managing our ESG initiatives.
Such assumptions and calculations or hypothetical scenarios are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established approach to identifying, measuring and reporting on many environmental, social and governance (“ESG”) matters. 45 Table of Contents The Board’s SSCR Committee is the primary committee responsible for overseeing and managing our ESG initiatives.
For example, in March 2022, the final UR from SENER regarding the development of the Zama Field in offshore Mexico, affirmed the appointment of PEMEX as operator of the unit, despite our discovery of the Zama Field in 2017 and subsequent operatorship.
For example, in March 2022, the final Unitization Resolution from SENER regarding the development of the Zama Field in offshore Mexico affirmed the appointment of PEMEX as operator of the unit, despite our discovery of the Zama Field in 2017 and subsequent operatorship.
The 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, 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 and Africa; • armed conflicts and hostilities such as Russia’s ongoing war in Ukraine and increasing hostilities in Israel and the Middle East; • the occurrence or threat of epidemic or pandemic diseases and other public health events; 33 Table of Contents • 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 ahead of the upcoming U.S. and Mexico presidential elections; • U.S. and foreign supply of oil and natural gas; • 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.
The 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.
The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities. Hedging transactions may limit our potential gains.
The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities. 37 Table of Contents Hedging transactions may limit our potential gains.
We may not be in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves from our non-operated properties. As we carry out our drilling program, we may not serve as operator of all planned wells.
We may not be in a position to control the timing of development efforts, associated costs or the rate of production of the reserves from our non-operated properties. We may not serve as operator of all our planned wells.
Under certain circumstances, regulations or federal laws such as the OCSLA could impose joint and several strict liability and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2023, we have accrued $3.3 million and $12.3 million in obligations reflected as “Other current liabilities” and “Other long-term liabilities”, respectively, on the Consolidated Balance Sheets.
Under certain circumstances, regulations or federal laws such as the OCSLA could impose joint and several strict liability and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2024, we have accrued $5.5 million and $14.5 million in obligations reflected as “Other current liabilities” and “Other long-term liabilities”, respectively, on the Consolidated Balance Sheets.
BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.
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.
Increasing attention to climate change and societal expectations on companies to address climate change and substitute energy sources for fossil fuels may result in increased costs, reduced demand for our products and our services and the products and services of our customers, reduced profits, increased compliance measures, investigations and litigation, and negative impacts on our stock price and access to capital markets.
In recent years, there has been increasing attention to climate change and societal expectations on companies to address climate change and substitute energy sources for fossil fuels, which may result in increased costs, reduced demand for our products and our services and the products and services of our customers, reduced profits, increased compliance measures, investigations and litigation, and negative impacts on our stock price and access to capital markets.
Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition. In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can economically produce.
Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, borrowing base under our Bank Credit Facility, results of operations and financial condition. In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can economically produce.
The U.S. inflation rate steadily rose in 2021 and into 2022 before eventually declining throughout 2023. These inflationary pressures resulted in increases to the costs of our goods, services and personnel, which in turn, caused our capital expenditures and operating costs to rise. The U.S.
The U.S. inflation rate steadily rose in 2021 and into 2022 before slightly declining during 2023 and 2024. These inflationary pressures resulted in increases to the costs of our goods, services and personnel, which in turn, caused our capital expenditures and operating costs to rise. The U.S.
At December 31, 2023, approximately 14% of our estimated proved reserves (by volume) were undeveloped and approximately 23% were non-producing. Any or all of our PUD or proved developed non-producing reserves may not be ultimately developed or produced.
At December 31, 2024, approximately 23% of our estimated proved reserves (by volume) were undeveloped and approximately 21% were non-producing. Any or all of our PUD or proved developed non-producing reserves may not be ultimately developed or produced.
Gulf of Mexico and in the shallow waters off the coast of Mexico. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes, tropical storms, loop currents and other adverse weather conditions in the U.S.
Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes, tropical storms, loop currents, winter storms and other adverse weather conditions in the U.S. Gulf of America.
Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2.
Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.
Under the Block 7 PSC, we are also 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, and failure to perform such obligations could result in contractual rescission of the PSC.
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.
Notwithstanding the above, BOEM, now under the Biden Administration, could, in the future, continue to make new demands for additional financial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities.
BOEM could, in the future, continue to make new demands for additional financial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities.
Numerous other executive actions and legislative and regulatory initiatives have been enacted or may be anticipated, such as cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.
Numerous other executive actions and legislative and regulatory initiatives have been enacted or may be anticipated at the federal, state or local level, such as cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.
We have no way to predict the progress or outcome of the war in Ukraine or its impacts in Ukraine, Russia or Belarus as the war, and any resulting government reactions, are rapidly developing and beyond our control.
We cannot predict the progress or outcome of the war in Ukraine or its impacts in Ukraine, Russia or Belarus as the war, and any resulting government reactions, are rapidly developing and beyond our control.
We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets are available to pay or refinance such debt.
We may not be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets are available to pay or refinance such debt.
Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG 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 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.
These regulatory actions, or any new laws, executive orders, regulations or other legal or enforcement initiatives, that impose increased costs or more stringent operational standards could delay or disrupt our operations, result in increased supplemental bonding and associated costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities or result in suspension or cancellation of leases.
Regulatory actions or any new laws, executive orders, regulations, judicial proceedings or other legal or enforcement initiatives, that impose increased restrictions, costs or more stringent operational standards could delay or disrupt our ability to obtain permits and governmental approvals, delay or restrict our operations, result in increased supplemental bonding and associated costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities or result in suspension or cancellation of leases.
All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS.
All of these factors may make it more difficult for us to obtain the financial assurances necessary to conduct operations on the OCS.
The loss of our larger customers, including Shell Trading (US) Company and Valero Energy 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 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 success and timing of development and exploitation activities on properties operated by others depends upon a number of factors that could be largely outside of our control, including: • the timing and amount of capital expenditures; • the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel; • the operator’s expertise and financial resources; • approval of other participants in drilling wells; • risk of other non-operator’s failure to pay its share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs; 41 Table of Contents • selection of technology; • the rate of production of the reserves; and • the timing and cost of P&A operations.
The success and timing of development and exploitation activities on properties operated by others further depends upon a number of factors that could be largely outside of our control, including: • the timing and amount of capital expenditures; • the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel; • the operator’s expertise, financial resources, qualified operating personnel and technology decisions; • approval of other participants in drilling wells; • the operator’s ability to obtain permits and regulatory approvals; • risk of other non-operator’s failure to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs; and • the timing and cost of P&A operations.
Future actions taken by the Biden Administration to limit the availability of new oil and gas leases on the OCS would adversely impact the offshore oil and gas industry and impact demand for our products.
Any future actions to limit the availability of new oil and gas leases on the OCS would adversely impact the offshore oil and gas industry and impact demand for our products.
Federal Reserve (the “Fed”) and other central banks increased interest rates multiple times in 2022 and 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S. and globally.
Federal Reserve (the “Fed”) and other central banks have periodically increased interest rates in an effort to curb inflationary pressure on the costs of goods and services across the U.S. and globally.
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.
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.
Increasing attention to environmental, social and governance matters may impact our business.
Any increased attention to environmental, social and governance matters may impact our business.
Gulf of Mexico. We are unable to predict what impact future incidents might have on our future results of operations and production. Epidemics, pandemics, outbreaks or other public health events that are outside of our control could significantly disrupt our operations and adversely affect our financial condition.
In addition, the unavailability of infrastructure may impact our ability to continue production. We are unable to predict what impact future incidents might have on our future results of operations and production. Epidemics, pandemics, outbreaks or other public health events that are outside of our control could significantly disrupt our operations and adversely affect our financial condition.
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.
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.
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.
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.
Business and Properties — Government Regulation — Hydrocarbon Export Regulation in Mexico for additional disclosure relating to the legal requirements imposed by SENER, CNH or other Mexican regulatory bodies to which we may be subject in the pursuit of our operations.
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.
This concentration of voting power could discourage a potential investor from seeking to acquire our common stock and, as a result, might harm the market price of our common stock.
Among other things, the Slim Family’s concentration of voting power could influence a sale of our company. This concentration of voting power could discourage a potential investor from seeking to acquire our common stock and, as a result, might harm the market price of our common stock.
Our operations are subject to various risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur and reduce demand for the crude oil and natural gas that we produce.
In addition, the CNH has the authority to rescind the PSC if these violations occur. 44 Table of Contents Our operations are subject to various risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur and reduce demand for the crude oil and natural gas that we produce.
If the military action concludes and the related sanctions are dropped, commodity prices could significantly decrease. Any of the above mentioned factors could affect our business, financial condition and results of operations. Additionally, on October 7, 2023, Hamas, a U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel.
Any of the above-mentioned factors could affect our business, financial condition and results of operations. Additionally, on October 7, 2023, Hamas, a U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel.
It is not possible at this time to predict or determine the ultimate consequence of these regional conflicts. These conflicts and their broader impacts could adversely affect our business, financial condition and results of operations and the global economy.
It is not possible at this time to predict or determine the ultimate consequence of these regional conflicts. These conflicts and their broader impacts could adversely affect our business, financial condition and results of operations and the global economy. Recent and pending management changes could disrupt our operations and impair our ability to attract and retain key personnel.
It is likely, however, that the new Five-Year Leasing Program will be subject to heightened environmental review. It is also possible that the program could be delayed by opposing lawsuits that were filed on February 12, 2024 by the American Petroleum Institute and by Earthjustice representing multiple environmental groups both of which are challenging BOEM’s actions.
It is possible, however, that this program could be delayed by opposing lawsuits that were filed on February 12, 2024 by the American Petroleum Institute and by Earthjustice representing multiple environmental groups both of which are challenging BOEM’s actions.
Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions, refunds (including refunds of value added taxes) and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate or have subsidiaries, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing business structure and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions. 46 Table of Contents 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.
Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions, refunds (including refunds of value added taxes) and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate or have subsidiaries, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing business structure and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeTo serve as an additional protection from outside threats, we also seek to prepare our employees and contractors about cybersecurity risks through training, simulated phishing exercises and awareness campaigns. We have implemented software and processes to help identify and evaluate risks from cybersecurity threats associated with third-party service vendors.
Biggest changeTo 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.
Cybersecurity risk is reviewed by a cross-functional, management-level ERM Steering Committee as part of the Company’s overall enterprise risk management program. 58 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. 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.
Impact of Risks from Cybersecurity Threats — 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 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.
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.”
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.
Our Director of Information Technology, who reports directly to the Chief Financial Officer (“CFO”) and Senior Vice President 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.
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.
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.
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.
Technology and cybersecurity policy decisions are made by our Director of Information Technology in consultation with our CFO and Senior Vice President. In addition, our Director of Information Technology has a direct line of communication with our President and CEO and Executive Vice President and General Counsel as needed.
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.
Our 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. We acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains.
Our 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.
Added
We have implemented software and processes and currently use a managed service to help identify and evaluate risks from cybersecurity threats associated with third-party service vendors.
Added
Impact of Risks from Cybersecurity Threats — The energy sector’s growing reliance on information and operational technology to manage critical business functions has significantly increased the exposure to cybersecurity threats. The rising frequency and sophistication of cyber incidents, whether resulting from deliberate attacks or accidental breaches, pose substantial risks to the energy industry.
Added
As these threats continue to evolve, effectively preventing, detecting, mitigating, and responding to cyber incidents has become an ongoing and increasingly complex challenge. Regulatory compliance adds another layer of complexity, particularly as cybersecurity reporting and disclosure requirements continue to evolve.
Added
These regulations require prompt and detailed disclosures of material cyber incidents, demanding significant resources and well-structured internal processes to maintain compliance. Failure to meet these obligations could lead to legal penalties, heightened regulatory oversight, and reputational harm. Additionally, the constantly shifting regulatory landscape may introduce overlapping or conflicting requirements, further complicating compliance efforts.
Added
To minimize potential risks, it is essential to closely monitor these developments and incorporate them into our cybersecurity and regulatory compliance strategies.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeIn 2018, the Jefferson Parish lawsuits were removed to the United States District Court for the Eastern District of Louisiana. The plaintiffs moved to remand the lawsuit to the state courts. Plaintiffs’ motions to remand were submitted to the state court for decision in two of the lawsuits on February 15, 2023.
Biggest changeIn 2018, the Jefferson Parish lawsuits were removed to the United States District Court for the Eastern District of Louisiana. Plaintiffs filed motions to remand the cases back to state court, which were granted by the federal district court on December 13, 2023. The defendants that filed the removals have appealed the orders of remand.
The plaintiffs have moved to remand the lawsuit to the state courts, but the case was administratively closed in federal court pending the appeal of another case, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone.
The plaintiffs moved to remand the lawsuit to the state courts, but the case was administratively closed in federal court pending the appeal of another case, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone.
In state court, the Plaquemines Parish lawsuit was stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. However, in 2018, the Plaquemines Parish lawsuit was removed to the United States District Court for the Eastern District of Louisiana.
In state court, the Plaquemines Parish lawsuit was stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. However, in 2018, the Plaquemines Parish lawsuit was removed to the United States District Court for the Eastern District of Louisiana (the “District Court”).
Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for more information. Item 4. Mine Saf ety Disclosures Not applicable. 60 Table of Contents PART II
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
As of December 31, 2023, the Company has recorded $14.3 million as “Other current liabilities” on the Condensed Consolidated Balance Sheets related to the litigation. 59 Table of Contents On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone Energy Corporation (“Stone”) and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, the “CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees.
On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone Energy Corporation (“Stone”) and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, the “CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees.
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. In June 2019, David M.
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.
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.
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.
That appeal was resolved by the United States Court of Appeals for the Fifth Circuit on December 15, 2022, and on December, 22, 2022, plaintiffs filed a motion in federal court to re-open the lawsuit. The United States Court of Appeals for the Fifth Circuit has not yet ruled on the plaintiffs’ motion to re-open.
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.
Removed
Plaintiffs filed motions to remand, which the District Court granted, remanding the lawsuits back to the 24 th Judicial District Court for the Parish of Jefferson. Defendants who removed the Jefferson Parish lawsuits have filed notices of appeal providing notice that they intend to appeal the District Court’s orders granting Plaintiffs’ motion to remand.
Added
(f/k/a Statoil USA E&P, Inc., and f/k/a Norsk Hydro USA Oil & Gas, Inc.) (“Equinor”) filed a complaint against Talos ERT LLC (“Talos ERT”) in the U.S. District Court for the Southern District of Texas, seeking to recover decommissioning and P&A expenses on a certain Gulf of America lease, Mississippi Canyon 941 (“MC 941 Lease”).
Removed
Plaintiffs filed motions to remand, which the District Court granted. However, the District Court also granted Defendants’ motion to stay the remand order pending appeal. That appeal is currently pending before the United States Court of Appeals for the Fifth Circuit.
Added
Equinor’s claim rests upon a purported indemnity set forth in a 2006 conveyance instrument in which a former affiliate of Equinor, Hydro Gulf of Mexico, LLC (“Hydro GOM”), sold a 25% interest in the MC 941 Lease to Energy Resource Technology GOM, Inc. (“ERT”) (n/k/a Talos ERT).
Added
That 25% lease interest was then conveyed to ATP Oil & Gas, Inc. a few months later. The interest was sold several times thereafter, including in 2017, when Equinor reacquired 100% of the MC 941 Lease.
Added
Production is continuing from the MC 941 Lease, and as a result, Equinor is seeking decommissioning costs not yet incurred and thus for unknown and unspecified amounts. On September 23, 2024, Talos ERT filed an answer denying all material allegations in Equinor’s complaint and asserting a counterclaim for declaratory relief.
Added
Talos ERT’s counterclaim relies upon indemnities provided pursuant to subsequent transactions of the 25% interest, which Talos ERT asserts Equinor assumed directly or owes as burdens running with the land that it acquired. Talos ERT’s counterclaim seeks a declaration that Equinor owes Talos ERT reimbursements for all decommissioning costs and Talos ERT’s legal fees in the litigation.
Added
On January 10, 2025, Equinor amended its complaint, expanding the scope of the alleged decommissioning obligations to include the Titan floating platform that was placed on location at the MC 941 Lease, years after ERT sold its interest in the MC 941 Lease in 2006, and the full cost to plug and abandon all wells on the MC 941 Lease.
Added
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.
Added
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.
Added
The appeals do not stay the state court proceedings.
Added
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.
Added
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.
Added
In the lead appeal proceedings, in May 2024, the Fifth Circuit affirmed the lower courts’ orders and remanded the cases to state court.
Added
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

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Biggest changeItem 4. Mine Safety Disclosures 60 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities 61 Item 6. [Reserved] 62 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 63 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 80 Item 8.
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.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeAs of December 31, 2023, there is $52.5 million remaining under the authorized program. 61 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.
Biggest changeThere 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.
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. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations.
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.
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, 2018 through December 31, 2023.
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.
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 21, 2024, there were approximately 180 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 19, 2025, there were approximately 209 holders of record of our common stock.
Exploration & Production Index $ 100 $ 110 $ 74 $ 131 $ 208 $ 216 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 $ 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.
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. There were no shares of common stock repurchased during the three months ended December 31, 2023.
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 graph assumes that $100 was invested in our common stock and each index on December 31, 2018 and that dividends were reinvested. 2018 2019 2020 2021 2022 2023 Talos Energy Inc. $ 100 $ 185 $ 50 $ 60 $ 116 $ 87 S&P 500 Index $ 100 $ 131 $ 156 $ 200 $ 164 $ 207 Dow Jones U.S.
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.
Added
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.

Item 7. Management's Discussion & Analysis

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

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Biggest changeWe 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. 73 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, 2023 2022 2021 Net income (loss) $ 187,332 $ 381,915 $ (182,952 ) Interest expense 173,145 125,498 133,138 Income tax expense (benefit) (60,597 ) 2,537 (1,635 ) Depreciation, depletion and amortization 663,534 414,630 395,994 Accretion expense 86,152 55,995 58,129 EBITDA 1,049,566 980,575 402,674 Write-down of oil and natural gas properties — — 18,123 Transaction and other (income) expense (1) (33,295 ) (34,513 ) 5,886 Decommissioning obligations (2) 11,879 31,558 21,055 Derivative fair value (gain) loss (3) (80,928 ) 272,191 419,077 Net cash received (paid) on settled derivative instruments (3) (9,457 ) (425,559 ) (290,164 ) (Gain) loss on debt extinguishment — 1,569 13,225 Non-cash write-down of other well equipment — — 5,606 Non-cash equity-based compensation expense 12,953 15,953 10,992 Adjusted EBITDA $ 950,718 $ 841,774 $ 606,474 (1) 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 expenses for the years ended December 31, 2023 and 2022, respectively.
Biggest changeWe 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.
There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A.
There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. Risk Factors.
The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of the deferred tax assets will not be realized.
The realization of our deferred tax assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of the deferred tax assets will not be realized.
For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies .
For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies .
The IRA 2022 provides for, among other things, the imposition of a new 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.
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.
(2) Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.
(2) Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information on decommissioning obligations.
(2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.
(2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies for additional information on decommissioning obligations.
At the end of the process, the Secretary of the Interior must submit the Proposed Final Program (“PFP”) to the President and to Congress for a period of at least 60 days, after which the program may be approved by the Secretary of the Interior and may take effect with no further regulatory or legislative action.
At the end of the process, the Secretary of the Interior must submit the Proposed Final Program to the President and to Congress for a period of at least 60 days, after which the program may be approved by the Secretary of the Interior and may take effect with no further regulatory or legislative action.
We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire the associated assets.
We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to plug, remove or retire the associated assets.
As a result of the derivative contracts we have on our anticipated production volumes through December 2025, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information.
As a result of the derivative contracts we have on our anticipated production volumes through December 2026, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information.
The energy transition will require both significant new investments in low-carbon energies and continued use of traditional hydrocarbons to meet the expected energy demand of an expanding global economy. Our historical focus in the Gulf of Mexico results in an asset profile that differentiates us from the typical shale-driven onshore exploration and production companies.
The energy transition will require both significant new investments in low-carbon energies and continued use of traditional hydrocarbons to meet the expected energy demand of an expanding global economy. Our historical focus in the Gulf of America results in an asset profile that differentiates us from the typical shale-driven onshore exploration and production companies.
Additionally, it includes a $13.9 million gain on the partial sale of our 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 .
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 additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies .
For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies .
Proved Reserve Estimates — We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test.
Proved Reserve Estimates — We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the carrying value of our proved oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test.
EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.
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.
We were in compliance with all debt covenants at December 31, 2023. 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, 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.
The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. 79 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. 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.
If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. During 2023, 2022 and 2021 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 2024, 2023 and 2022 our ceiling test computations for our U.S. oil and gas properties did not result in a write down.
This section of this Annual Report generally discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 that are not included in this Annual Report can be found in “Part II, Item 7.
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.
See additional information on the valuation allowance as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — 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 14 — Commitments and Contingencies .
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 .
See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.
See the subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.
Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows. Recently Adopted Accounting Standards None.
Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows.
For additional information regarding these liabilities, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 9 — Asset Retirement Obligations . Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part IV, Item 15.
Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 — Commitment and Contingencies .
Year Ended December 31, 2023 2022 2021 Oil: NYMEX WTI high per Bbl $ 89.43 $ 114.84 $ 81.48 NYMEX WTI low per Bbl $ 70.25 $ 76.44 $ 52.01 Average NYMEX WTI per Bbl $ 77.63 $ 94.79 $ 67.99 Average oil sales price per Bbl (including commodity derivatives) $ 73.59 $ 68.40 $ 49.67 Average oil sales price per Bbl (excluding commodity derivatives) $ 75.17 $ 93.75 $ 65.86 Natural Gas: NYMEX Henry Hub high per MMBtu $ 3.27 $ 8.81 $ 5.51 NYMEX Henry Hub low per MMBtu $ 2.14 $ 4.38 $ 2.62 Average NYMEX Henry Hub per MMBtu $ 2.54 $ 6.42 $ 3.91 Average natural gas sales price per Mcf (including commodity derivatives) $ 3.32 $ 5.30 $ 3.11 Average natural gas sales price per Mcf (excluding commodity derivatives) $ 2.60 $ 7.06 $ 3.98 NGLs: NGL realized price as a % of average NYMEX WTI 23 % 35 % 39 % 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, 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.
In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate.
In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations.
Pursuant to the United States Court of Appeals for the Fifth Circuit’s November 14, 2023 order, BOEM held Lease Sale 261 on December 20, 2023, in which we were the high bidder on thirteen offshore blocks and were awarded four leases as of February 16, 2024.
Pursuant to the United States Court of Appeals for the Fifth Circuit’s November 14, 2023 order, BOEM held Lease Sale 261 on December 20, 2023, in which we were the high bidder on thirteen offshore blocks and were awarded leases on all of our high-bid blocks.
Other Operating (Income) Expense — During the year ended December 31, 2023, we recognized a gain of $66.2 million on the Mexico Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.
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.
The 11.75% Notes were secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility.
The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility.
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 board approved 2024 Upstream capital spending program of $565.0 million to $595.0 million and plugging & abandonment and decommissioning obligations of $90.0 million to $100.0 million.
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.
We have historically focused our operations in the U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market.
Gulf of America because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market.
Equity Method Investment Income — During the year ended December 31, 2023, we recorded $12.1 million of equity losses offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron.
Equity Method Investment (Income) Expense — During the year ended December 31, 2024, we recorded equity losses of $10.3 million. During the year ended December 31, 2023, we recorded $12.1 million of equity losses offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron U.S.A. Inc. (“Chevron”).
This gain was partially offset by $11.9 million of estimated decommissioning obligations primarily as a result of unrelated parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the year ended December 31, 2022, we recorded $31.6 million of estimated decommissioning obligations. See Part IV, Item 15.
This gain was partially offset by $8.6 million of estimated decommissioning obligations primarily as a result of unrelated parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the year ended December 31, 2023, we recognized a gain of $66.2 million on the 2023 Mexico Divestiture. See Part IV, Item 15.
Oil spill response plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made.
Oil spill response plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.
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.
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.
How We Evaluate Our Operations We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: • production volumes; • realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts; • lease operating expenses; • capital expenditures; and • Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below. 67 Table of Contents Basis of Presentation Sources of Revenues Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs, that are extracted from our natural gas during processing.
How We Evaluate Our Operations We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: • production volumes; • realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts; • lease operating expenses; • capital expenditures; and • Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.
Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.
Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.
If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2023 and ending December 1, 2023 used in the determination of the SEC pricing was 10% lower, resulting in $70.73 per Bbl of oil, $2.48 per Mcf of natural gas and $16.89 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $321.9 million.
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.
The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. For additional details on our Bank Credit Facility, see Part IV, Item 15.
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.
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.
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.
If the proved reserves used had been a 10 percent lower, depreciation, depletion and amortization in the three months ended December 31, 2023 would have increased by an estimated $19.4 million.
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.
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.
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.
We had net borrowings from the Bank Credit Facility of $200.0 million for the year ended December 31, 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures.
We had net borrowings from the Bank Credit Facility of $200.0 million during the corresponding period in 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures.
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.
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 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, 2023 2022 Lease operating expenses $ 389,621 $ 308,092 Lease operating expenses per Boe $ 16.10 $ 14.18 Total lease operating expenses for the year ended December 31, 2023 increased by approximately $81.5 million, or 26%.
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): Year Ended December 31, 2023 2022 Depreciation, depletion and amortization $ 663,534 $ 414,630 Depreciation, depletion and amortization expense for the year ended December 31, 2023 increased by approximately $248.9 million, or 60%.
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%.
Under the proposed rule, BOEM would no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance should be provided by current lessees and grant holders.
The final rule provides that BOEM will no longer consider or rely upon the financial strength of predecessors in title in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders.
The current federal administration has proposed increasing the excise tax amount from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect.
In the past, there have been proposals to increase the amount of the excise tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect.
At December 31, 2023, the Company’s ceiling test computation was based on SEC pricing of $78.56 per Bbl of oil, $2.75 per Mcf of natural gas and $18.77 per Bbl of NGLs.
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.
Exhibits and Financial Statement Schedules — Note 5 — Leases for additional information on the HP-I lease extension. 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.
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.
During January 1, 2023 through December 31, 2023, the daily spot prices for NYMEX WTI crude oil ranged from a high of $93.67 per Bbl to a low of $66.61 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.78 per MMBtu to a low of $1.74 per MMBtu.
During January 1, 2024 through December 31, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $87.69 per Bbl to a low of $66.73 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $13.20 per MMBtu to a low of $1.21 per MMBtu.
The expense of $272.2 million for the year ended December 31, 2022 consisted of $425.6 million in cash settlement losses and $153.4 million in non-cash gains from the increase in the fair value of our open derivative contracts.
The expense of $1.5 million for the year ended December 31, 2024 consisted of $6.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts offset by $4.7 million in cash settlement gains.
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 has increased. By raising its federal funds rate, the Fed is making it more expensive to borrow money.
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.
Deepwater Operations — We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010.
Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010.
Overview of Debt Instruments Financing Arrangements — As of December 31, 2023, total debt, net of discount and deferred financing costs, was approximately $1,025.7 million, comprised of our $866.0 million aggregate principal amount of the 12.00% Notes and 11.75% Notes (as defined herein) and $200.0 million outstanding under our Bank Credit Facility.
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.
Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position.
Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate an inventory of high-quality prospects, which we believe greatly improves our development and exploration success.
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 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.
Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information. Common Stock Repurchase Program — On March 20, 2023, we announced that our Board of Directors approved a $100.0 million common stock repurchase program.
Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures, Note 8 — Debt and Note 10 — Stockholders’ Equity for additional information. Common Stock Repurchase Program — 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.
The information below provides the financial results and an analysis of significant variances in these results (in thousands): Year Ended December 31, 2023 2022 Accretion expense $ 86,152 $ 55,995 Other operating (income) expense $ (52,155 ) $ 33,902 Interest expense $ 173,145 $ 125,498 Price risk management activities (income) expense $ (80,928 ) $ 272,191 Equity method investment (income) expense $ (3,209 ) $ (14,222 ) Other (income) expense $ (12,371 ) $ (31,800 ) Income tax (benefit) expense $ (60,597 ) $ 2,537 Accretion Expense — During the year ended December 31, 2023, we recorded $86.2 million of accretion expense compared to $56.0 million during the year ended December 31, 2022.
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.
Common Stock Repurchase Program — 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. In March and June of 2023, we repurchased 1.9 million shares for $26.6 million and 1.5 million shares for $20.9 million, respectively.
Common Stock Repurchase Program — 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. During the year ended December 31, 2023 and six months ended June 30, 2024, we repurchased 3.4 million shares for $47.5 million and 3.8 million shares for $42.9 million, respectively.
As of December 31, 2023, we believe it is more likely than not that some or all of the benefits from our state deferred tax assets will not be realized and reduced the state deferred tax assets by a valuation allowance. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes.
A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes.
Moreover, BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning obligations.
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.
On May 11, 2022, the DOI cancelled two lease auctions in the Gulf of Mexico, Lease Sales 259 and 261 included in the 2017-2022 national program that was developed under the Obama Administration, which expired on June 30, 2022. The DOI cited “conflicting court rulings” as the primary reason for not holding the two Gulf of Mexico lease sales.
Outer Continental Shelf. On May 11, 2022, the DOI cancelled two lease auctions in the Gulf of America, Lease Sales 259 and 261 included in the 2017-2022 Five-Year Leasing Program that was developed under the Obama Administration, which expired on June 30, 2022.
Five-Year Offshore Oil and Gas Leasing Program Update — Under the OCSLA, as amended, BOEM within the DOI must prepare and maintain forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the U.S. Outer Continental Shelf.
Significant impacts could include reductions and/or deferrals of future oil and natural gas production and revenues and increased lease operating expenses for evacuations and repairs. 64 Table of Contents Five-Year Offshore Oil and Gas Leasing Program Update — Under the OCSLA, as amended, BOEM within the DOI must prepare and maintain forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the U.S.
Additionally, these plans are tested and drills are conducted periodically at all levels. 66 Table of Contents Hurricanes, Tropical Storms and Loop Currents — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes, tropical storms and loop currents on production and capital projects.
Hurricanes, Tropical Storms, Winter Storms and Loop Currents — Since our operations are in the U.S. Gulf of America, we are particularly vulnerable to the effects of hurricanes, tropical storms, winter storms and loop currents on production and capital projects.
The following table presents a breakout of each revenue component: Year Ended December 31, 2023 2022 2021 Oil 93 % 83 % 86 % Natural gas 5 % 14 % 10 % NGL 2 % 4 % 4 % Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
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.
As of December 31, 2023, we have repurchased 3.4 million shares for a total of $47.5 million resulting in $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.
We have repurchased an aggregate of 7.4 million shares under our authorized program for a total of $92.6 million resulting in approximately $157.4 million remaining under our authorized program as of December 31, 2024. All repurchased shares are held in treasury.
The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively.
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.
Exhibits and Financial Statement Schedules — Note 8 — Debt . 72 Table of Contents Income Tax Benefit (Expense) — During the year ended December 31, 2023, we recorded $60.6 million of income tax benefit compared to $2.5 million of income tax expense during the year ended December 31, 2022, primarily due to a non-cash tax benefit of $106.8 million related to the release of the valuation allowance for our deferred tax assets partially offset with an income tax expense of $31.1 million related to current year activity inclusive of permanent differences for the year ended December 31, 2023.
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.
Cash 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. 69 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, 2023 2022 Change Revenues: Oil $ 1,357,732 $ 1,365,148 $ (7,416 ) Natural gas 68,034 227,306 (159,272 ) NGL 32,120 59,526 (27,406 ) Total revenues $ 1,457,886 $ 1,651,980 $ (194,094 ) Production Volumes: Oil (MBbls) 18,062 14,561 3,501 Natural gas (MMcf) 26,194 32,215 (6,021 ) NGL (MBbls) 1,767 1,793 (26 ) Total production volume (MBoe) 24,195 21,723 2,472 Daily Production Volumes by Product: Oil (MBblpd) 49.5 39.9 9.6 Natural gas (MMcfpd) 71.8 88.3 (16.5 ) NGL (MBblpd) 4.8 4.9 (0.1 ) Total production volume (MBoepd) 66.3 59.5 6.8 Average Sale Price per Unit: Oil (per Bbl) $ 75.17 $ 93.75 $ (18.58 ) Natural gas (per Mcf) $ 2.60 $ 7.06 $ (4.46 ) NGL (per Bbl) $ 18.18 $ 33.20 $ (15.02 ) Price per Boe $ 60.26 $ 76.05 $ (15.79 ) Price per Boe (including realized commodity derivatives) $ 59.86 $ 56.46 $ 3.40 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 $ (335,635 ) $ 328,219 $ (7,416 ) Natural gas (116,764 ) (42,508 ) (159,272 ) NGL (26,543 ) (863 ) (27,406 ) Total revenues $ (478,942 ) $ 284,848 $ (194,094 ) Volumetric Analysis — Production volumes increased by 6.8 MBoepd to 66.3 MBoepd for the year ended December 31, 2023.
Cash 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.
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.
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.
Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties. 65 Table of Contents BOEM Bonding Requirements — In 2016, BOEM issued the 2016 NTL, which bolstered supplemental bonding requirements for offshore oil and gas lessees.
The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.
Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. 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 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 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, 2023 2022 Upstream Segment $ 139,026 $ 82,979 CCS Segment 11,922 10,240 Unallocated corporate 7,545 6,535 Total general and administrative expense $ 158,493 $ 99,754 Upstream general and administrative expense per Boe $ 5.75 $ 3.82 General and administrative expense for the year ended December 31, 2023, increased by approximately $58.7 million, or 59%.
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%.
As of December 31, 2023, there is $52.5 million remaining under the authorized program. 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.
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.
See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures and Note 10 — Employee Benefit Plans and Share-Based Compensation . Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance.
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.
The shut-in resulted in an estimated deferred production of approximately 1.6 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in. The next dry-dock is scheduled for the first half of 2024 with a projected shut-in period of approximately 55 days.
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.
In addition, the U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. These inflationary pressures 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.
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.
We are continuing to explore a capital raise to finance the accelerated growth of our CCS segment. 74 Table of Contents Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2023 (in thousands): U.S. drilling & completions $ 447,254 Mexico appraisal & exploration 291 Asset management (1) 83,970 Seismic and G&G, land, capitalized G&A and other 64,955 Total Upstream capital expenditures 596,470 Plugging & abandonment 86,615 Decommissioning obligations settled (2) 50,584 Total Upstream 733,669 Investment in CCS 40,961 Total $ 774,630 (1) Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure.
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.
Exhibits and Financial Statement Schedules — Note 8 — Debt . Price Risk Management Activities — Price risk management activities for year ended December 31, 2023 resulted in a decrease of approximately $353.1 million, or 130%.
Price Risk Management Activities — Price risk management activities for year ended December 31, 2024 resulted in a decrease of approximately $82.4 million, or 102%.
The IRA, which President Biden signed into law on August 16, 2022, reinstated Lease Sale 257 held in November 2021, and required the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders.
The DOI cited “conflicting court rulings” as the primary reason for not holding the two Gulf of America lease sales. The IRA 2022 reinstated Lease Sale 257 held in November 2021, and required the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeA 10% change in the SOFR rate on this variable rate debt balance at December 31, 2023 would change interest expense for the year ended December 31, 2023 by approximately $1.1 million. For additional information regarding the borrowing base utilization percentage associated with our Bank Credit Facility, see Part IV, Item 15.
Biggest changeFor 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 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, 2023, our interest rate risk exposure is mitigated as a result of fixed interest rates on 81% 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, 2024, our interest rate risk exposure is mitigated as a result of fixed interest rates on 100% of our debt.
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, 2023, our average oil price realizations after the effect of derivatives increased 8% to $73.59 per Bbl from $68.40 per Bbl in the comparable 2022 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, 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.
Our average natural gas price realizations after the effect of derivatives decreased 37% during the year ended December 31, 2023 to $3.32 per Mcf from $5.30 per Mcf in the comparable 2022 period.
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 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. 80 Table of Contents We had commodity derivative instruments in place to reduce the price risk associated with future production of 9,833 MBbls of crude oil and 15,515 MMBtu of natural gas at December 31, 2023, with a net derivative asset position of $45.6 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. 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.
The remaining $200.0 million is from outstanding borrowings under our Bank Credit Facility with variable interest rates. We 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.
We 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.
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, 2023 (in thousands): Oil and Natural Gas Derivatives Ten Percent Increase Ten Percent Decrease Fair Value Fair Value Change Fair Value Change Price impact (1) $ 45,603 $ (21,481 ) $ (67,084 ) $ 113,601 $ 67,998 (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, 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.
Variable Interest Rate Risks We had total debt outstanding of $1,066.0 million at December 31, 2023, before unamortized original issue discount and deferred financing costs. Of this, $866.0 million aggregate principal was from our 12.00% Notes and 11.75% Notes, which bears interest at a fixed rate.
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.
Removed
The all-in interest rate on our variable rate debt at December 31, 2023 was 8.26%, which includes a spread of 2.85% based on the utilization rate of our Bank Credit Facility, and a secured overnight financing rate (”SOFR”) of 5.41%.
Removed
Exhibits and Financial Statement Schedules — Note 8 — Debt , included elsewhere in this Annual Report.

Other TALO 10-K year-over-year comparisons