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What changed in TALOS ENERGY INC.'s 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of TALOS ENERGY INC.'s 2022 and 2023 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 2023 report.

+455 added−456 removedSource: 10-K (2024-02-29) vs 10-K (2023-03-01)

Top changes in TALOS ENERGY INC.'s 2023 10-K

455 paragraphs added · 456 removed · 277 edited across 5 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

156 edited+73 added−95 removed177 unchanged
Biggest changeGulf of Mexico and in the shallow waters off the coast of Mexico means that some or all of our properties could be affected should the region experience: • severe weather, such as hurricanes, winter storms, tornadoes and other adverse climatic conditions; • delays or decreases in production or the availability of equipment, facilities or services; • delays or decreases in the availability or capacity to transport, gather or process production; • changes in the status of pipelines that we depend on for transportation of our production to the marketplace; • extensive governmental regulation (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; • changes in the regulatory environment such as the guidelines issued by the BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS; and/or 40 Table of Contents • 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.
Biggest changeAs 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.
Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas.
Our need to generate revenues to fund ongoing capital commitments and/or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas.
The 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 to assure satisfaction of lease obligations, including decommissioning activities on the OCS.
Following the effectiveness of the 2016 NTL, we received orders from the BOEM in late 2016 directing us to provide additional financial assurance in material amounts relating to our OCS properties.
Following the effectiveness of the 2016 NTL, we received orders from BOEM in late 2016 directing us to provide additional financial assurance in material amounts relating to our OCS properties.
We entered into discussions with the BOEM regarding the requested additional financial security and submitted a proposed tailored plan (applicable to our sole and non-sole liability properties) for the posting of additional financial security to the agency for review. However, as the Trump Administration rescinded the 2016 NTL, the BOEM withdrew the previously issued orders under the 2016 NTL.
We entered into discussions with BOEM regarding the requested additional financial security and submitted a proposed tailored plan (applicable to our sole and non-sole liability properties) for the posting of additional financial security to the agency for review. However, as the Trump Administration rescinded the 2016 NTL, BOEM withdrew the previously issued orders under the 2016 NTL.
In August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets.
In August 2021, BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets.
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. 46 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.
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. 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.
In addition, at times the attention of certain members of our management and resources may be focused on the integration of the businesses of the two companies and diverted from day-to-day business operations or other opportunities that may have been beneficial to us, which may disrupt our ongoing business. Item 1B. Un resolved Staff Comments None.
In addition, at times the attention of certain members of our management and resources may be focused on the integration of the businesses of the companies and diverted from day-to-day business operations or other opportunities that may have been beneficial to us, which may disrupt our ongoing business. Item 1B. Un resolved Staff Comments None.
Specifically, the following issues, among others, must be addressed in integrating the operations in order to realize the anticipated benefits of the EnVen Acquisition: • combining the companies’ operations and corporate functions and the resulting difficulties associated with managing a larger, more complex, integrated business; • combining our business with EnVen in a manner that permits the combined company to achieve any cost savings or operating synergies anticipated to result from the EnVen Acquisition; • reducing additional and unforeseen expenses such that integration costs are not more than anticipated; • minimizing the loss of key employees; • identifying and eliminating redundant functions and assets; • maintaining existing agreements with customers, providers and vendors or business partners and avoiding delays in entering into new agreements with prospective customers, providers and vendors or business partners; and • consolidating the companies’ operating, administrative and information technology infrastructure.
Specifically, the following issues, among others, must be addressed in integrating the operations in order to realize the anticipated benefits of the QuarterNorth Acquisition: • combining the companies’ operations and corporate functions and the resulting difficulties associated with managing a larger, more complex, integrated business; • combining our business with QuarterNorth in a manner that permits the combined company to achieve any cost savings or operating synergies anticipated to result from the QuarterNorth Acquisition; • reducing the additional and unforeseen expenses such that integration costs are not more than anticipated; • minimizing the loss of key employees; • identifying and eliminating redundant functions and assets; • maintaining existing agreements with customers, providers and vendors or business partners and avoiding delays in entering into new agreements with prospective customers, providers and vendors or business partners; and • consolidating the companies’ operating, administrative and information technology infrastructure.
If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.
If in the future BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our associated federal offshore leases.
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. 55 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. 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.
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; 47 Table of Contents • 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; • 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 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.
In order to manage our exposure to price risks in the marketing of our oil, natural gas and NGLs, we periodically enter into oil, natural gas and NGLs price hedging arrangements with respect to a portion of our expected production. These arrangements may include futures contracts on the NYMEX.
In order to manage our exposure to price risks in the marketing of our oil, natural gas and NGLs, we periodically enter into oil, natural gas and NGL price hedging arrangements with respect to a portion of our expected production. These arrangements may include futures contracts on the NYMEX.
These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others. 66 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. 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.
If we fail to comply with the current or future orders of the BOEM to provide additional surety bonds or other financial assurances, the BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.
If we fail to comply with the current or future orders of BOEM to provide additional surety bonds or other financial assurances, BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases associated with our noncompliance, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.
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; 41 Table of Contents • supply of and demand for oil and natural gas; • actual prices we receive for oil and natural gas; and • our actual operating costs in producing oil and natural gas.
Further, actual future net revenues are affected by factors such as: • 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.
Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. See Items 1 and 2.
Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. See Part I, Items 1 and 2.
In September 2022, BOEM announced that it was reinstating the lease results in line with congressional direction in the IRA 2022. In addition, there is increasing uncertainty regarding the near-term future of Gulf of Mexico lease sales. These lease sales are conducted pursuant to Five-Year Leasing Programs under the Outer Continental Shelf Lands Act.
In September 2022, BOEM announced that it was reinstating Lease Sale 257 results in line with congressional direction in the IRA 2022. In addition, there is increasing uncertainty regarding the near-term future of Gulf of Mexico lease sales. These lease sales are conducted pursuant to Five-Year Leasing Programs under the Outer Continental Shelf Lands Act.
Any material inaccuracies in these reserve estimates or underlying assumptions materially affects the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition. Our acreage has to be drilled before lease expirations in order to hold the acreage by production.
Any material inaccuracies in these reserve estimates or underlying assumptions materially affects the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition. Our acreage must be drilled before lease expirations in order to hold the acreage by production.
Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce or eliminate future emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.
Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce or eliminate future GHG emissions could have an adverse effect on our business, financial condition and results of operations.
The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including: • incurring additional debt; 61 Table of Contents • paying dividends on stock, redeeming stock or redeeming subordinated debt; • making investments; • creating liens on our assets; • selling assets; • guaranteeing other indebtedness; • entering into agreements that restrict dividends from our subsidiaries to us; • merging, consolidating or transferring all or substantially all of our assets; • hedging future production; and • entering into transactions with affiliates.
The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including: • incurring additional debt; • paying dividends on stock, redeeming stock or redeeming subordinated debt; • making investments; • creating liens on our assets; • selling assets; • guaranteeing other indebtedness; • entering into agreements that restrict dividends from our subsidiaries to us; • merging, consolidating or transferring all or substantially all of our assets; • hedging future production; and • entering into transactions with affiliates.
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. 52 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. 44 Table of Contents We reevaluate the purchase of insurance, policy limits and terms annually.
Business and Properties— Summary of Reserves for further discussion on 2022 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 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.
We base the estimated discounted future net cash flows from our proved reserves at December 31, 2022 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, 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.
Our oil and gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, royalty and tax increases and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to acts of terrorism, piracy, disease, illegal cartel activities and other political risks, including tension and confrontations among political parties.
Our oil and gas activities are subject to numerous geopolitical and economic risks, uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, royalty and tax increases, and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to acts of terrorism, piracy, disease, illegal cartel activities and other political risks, including tension and confrontations among political parties.
Moreover, as operator of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response.
Moreover, as operator for two of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response.
We note, however, that our ESG governance structure may not be able to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve our GHG emissions intensity reduction or other ESG-related aspirational goals, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such goals.
We note, however, that our governance structure may not be able to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve our GHG emissions targets or other ESG-related aspirational goals, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such goals.
Development of successful CCS projects will also require satisfying certain operational factors, such as locating a suitable source of anthropogenic CO 2 and reaching suitable agreements to capture that CO 2 . Such agreements are complex and may involve allocation of not only fees but also various credits, incentives and environmental attributes associated with the sequestration of CO 2 .
CCS projects also require satisfying certain operational factors, such as locating a suitable source of anthropogenic CO 2 and reaching suitable agreements to capture that CO 2 . Such agreements are complex and may involve allocation of not only fees but also various credits, incentives and environmental attributes associated with the sequestration of CO 2 .
Also, a sustained lower commodity price environment may cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs. 64 Table of Contents We have divested, as assignor, various leases, wells and facilities located in the U.S.
Also, a sustained lower commodity price environment may cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs. We have divested, as assignor, various leases, wells and facilities located in the U.S.
These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. 45 Table of Contents The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject our operations to increased risks.
These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject our operations to increased risks.
In addition, our forecasts may assume that none of the risks associated with our oil and natural gas operations summarized in this section would occur, such as facility or equipment malfunctions, adverse weather effects, adverse resolutions to disputes relating to operatorships (such as that observed with the Zama Field dispute) or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.
In addition, our forecasts may assume that none of the risks associated with our oil and natural gas operations summarized in this section would occur, such as facility or equipment malfunctions, adverse weather effects, adverse resolutions to disputes relating to operatorships or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.
District Court for the District of Columbia vacated the November 2021 lease sale and the related agency decision making process, finding that the BOEM failed to consider the impact on foreign greenhouse gas emissions if the November 2021 lease sale was not held and the court determined that this failure was a violation of the NEPA.
District Court for the District of Columbia vacated Lease Sale 257 and the related agency decision making process, finding that BOEM failed to consider the impact on foreign greenhouse gas emissions if Lease Sale 257 was not held and the court determined that this failure was a violation of the NEPA.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance in these factors could materially affect the estimated quantities and present value of reserves.
In November 2021, the Biden Administration conducted an offshore lease sale and various industry participants submitted bids for leases in the Gulf of Mexico; however, on January 27, 2022, in litigation brought by Friends of the Earth and other plaintiffs, the U.S.
In November 2021, the Biden Administration conducted Lease Sale 257 and various industry participants submitted bids for leases in the Gulf of Mexico; however, on January 27, 2022, in litigation brought by Friends of the Earth and other plaintiffs, the U.S.
We may not realize all of the anticipated benefits from our future acquisitions, and we may be unable to successfully integrate future acquisitions. Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market.
We may not realize the anticipated benefits from our current and future acquisitions, and we may be unable to successfully integrate future acquisitions. Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies and Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies for more information.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies and Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for more information.
There is no assurance that we will be successful in obtaining permits or adequate levels of financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition or otherwise.
There is no assurance that we will be successful in obtaining sufficient federal and state permits or adequate levels of financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition or otherwise.
This could result in a current or future tax liability, which could adversely affect our financial condition and cash flows. We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.
This could result in a current or future tax liability, 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.
These laws and regulations require the acquisition of a permit or other approval before drilling or other regulated activity commences; restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; limit or prohibit exploration or drilling activities on certain lands lying within protected areas or that may affect certain wildlife, including marine species and endangered and threatened species and impose substantial liabilities for pollution resulting from our operations.
These laws and regulations require permits or other approvals before drilling or other regulated activity commences; restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; limit or prohibit exploration or drilling activities on certain lands lying within protected areas or that may affect certain wildlife, including marine species and endangered and threatened species and impose substantial liabilities for pollution resulting from our operations.
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. 48 Table of Contents O ur operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine mammals 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. 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.
We are required to elect one of the foregoing options within 10 days after the existence of such deficiency. 62 Table of Contents We may not have sufficient funds to make such repayments.
We are required to elect one of the foregoing options within 10 days after the existence of such deficiency. We may not have sufficient funds to make such repayments.
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, 2022, we have accrued $42.1 million and $12.2 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, 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.
Estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex.
These estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Future sales, or the perception of future sales, by us or our existing stockholders in the public market following the EnVen Acquisition could cause the market price for our common stock to decline.
Future sales, or the perception of future sales, by us or our existing stockholders in the public market could cause the market price for our common stock to decline.
As a result, we cannot assure whether we will be able to obtain sufficient quantities of CO 2 from emitters on terms that are acceptable to us, and the failure to do so may have a material impact on our ability to execute our CCS strategy.
As a result, we may not be able to obtain sufficient quantities of CO 2 from emitters on terms that are acceptable to us, and the failure to do so may have a material impact on our ability to execute our CCS strategy.
In connection with this Note to Stakeholders, BOEM initially assessed the required financial assurance for our sole liability properties as approximately $70 million. However, following the opportunity to review BOEM’s sole liability assessment, we were able to reduce the financial assurance required to approximately $37.7 million.
In connection with this Note to Stakeholders, BOEM initially assessed the required financial assurance for our sole liability properties as approximately $70 million. However, following the opportunity to review BOEM’s sole liability assessment, we were able to reduce the financial assurance required to approximately $37.7 million. The bonds covering this amount were posted in 2021.
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 oil and gas operations are subject to various international, foreign and U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions.
Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions.
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 these gathering systems, pipelines and processing facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for 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 of this infrastructure could result in the shut-in of producing wells or delays or discontinuance of development plans for our properties.
In 2016, the BOEM under the Obama Administration had sought to implement more stringent and costly standards under the existing federal financial assurance requirements through issuance and implementation of the 2016 NTL, but former President Trump’s Administration first suspended, and then in 2020 rescinded, the implementation of this NTL.
In 2016, BOEM under the Obama Administration had sought to implement more stringent and costly standards under the existing federal financial assurance requirements through issuance and implementation of the 2016 NTL, but the Trump Administration first suspended, and then in 2020 rescinded, the implementation of the 2016 NTL.
These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition. 57 Table of Contents We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act (the “FCPA”).
These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition. 47 Table of Contents We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act. We are subject to the U.S.
Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our assessments, we perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
In connection with our assessments, we perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
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 indenture for our 12.00% 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 New Senior Notes, may also prohibit us from taking such actions.
Exploration for oil or natural gas in the Deepwaters of the U.S. Gulf of Mexico generally involves greater operational and financial risks than exploration in the shallower waters of the U.S. Gulf of Mexico conventional shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs.
Gulf of Mexico generally involves greater operational and financial risks than exploration in the shallower waters of the U.S. Gulf of Mexico conventional shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs.
As CCS and carbon management represent an emerging sector, regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects.
As carbon management represents an emerging sector, regulations may evolve rapidly and unpredictably, which could impact the feasibility of one or more of our anticipated projects.
Risks Related to our Business and the Oil and Natural Gas Industry Oil and natural gas prices are volatile. Stagnation or declines in commodity prices may adversely affect our financial condition and results of operations, cash flows, access to the capital markets and ability to grow.
Risks Related to our Business and the Oil and Natural Gas Industry Oil and natural gas prices are volatile. Stagnation or declines in commodity prices may adversely affect our financial condition and results of operations, cash flows, access to the capital markets and available borrowings under our Bank Credit Facility and our ability to grow.
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. Climate change continues to attract considerable public, political and scientific attention.
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.
Business and Properties— Acreage for further discussion. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
It is possible that the integration process of our business with EnVen’s could result in the loss of key employees, customers, providers, vendors or business partners, the disruption of either company’s or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.
The integration process of our business with those of QuarterNorth could result in the loss of key employees, customers, providers, vendors or business partners, the disruption of each company’s or all companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated.
Moreover, a depressed oil price environment could result in sureties seeking additional collateral to support existing bonds, such as cash or letters of credit, and we cannot provide assurance that we will be able to satisfy collateral demands for future bonds to comply with supplemental bonding requirements of the BOEM.
Moreover, the implementation of such new regulations could result in sureties seeking additional collateral to support existing or future bonds, such as cash or letters of credit, and we cannot provide assurance that we will be able to satisfy collateral demands for such bonds to comply with supplemental bonding requirements of BOEM.
In the event that the FERC were to determine that CKB Petroleum, Inc. no longer qualified for a waiver, we would likely be required to file a tariff with the FERC, provide a cost justification for the transportation charge and provide service to all potential shippers without undue discrimination.
In the event that the FERC determines the pipeline no longer qualified for a waiver, we would likely be required to file a tariff with the FERC, provide a cost justification for the transportation charge and provide service to all potential shippers without undue discrimination.
Separately, permitting CCS projects also requires obtaining a number of other permits and approvals unrelated to subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility.
Separately, CCS projects are also subject to additional permits and approvals unrelated to subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility.
To the extent regulatory requirements are imposed, are amended or more stringently enforced, we may incur additional costs in the pursuit of one or more of our CCS projects, which costs may be material or may render any one or more of our CCS projects uneconomical.
To the extent regulatory requirements are imposed, are increased or more stringently enforced, we may incur additional costs in the development of our CCS projects, which costs may be material or may render any one or more of our projects uneconomic.
At December 31, 2022, approximately 17% 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.
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.
In addition, the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. This could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.
Further, the incentives offered for various clean energy industries could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. These regulatory changes could ultimately decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.
Additional drilling laws, regulations, executive orders and other regulatory initiatives that restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to locations where such activities may occur could have a material adverse effect on our business, financial condition or results of operations.
Any regulatory developments that impact, curtail or increase the cost of our oil and natural gas exploration and production activities on the OCS could have a material adverse effect on our business, results of operations and financial condition. 42 Table of Contents Additional drilling laws, regulations, executive orders and other regulatory initiatives that restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to locations where such activities may occur could have a material adverse effect on our business, financial condition or results of operations.
For example, during the period January 1, 2020 through December 31, 2022, the daily NYMEX WTI crude oil price per Bbl ranged from a low of $(36.98) to a high of $123.64, and the daily NYMEX Henry Hub natural gas price per MMBtu ranged from a low of $1.33 to a high of $23.86.
For example, during the period January 1, 2021 through December 31, 2023, the daily NYMEX WTI crude oil price per Bbl ranged from a low of $47.47 to a high of $123.64, and the daily NYMEX Henry Hub natural gas price per MMBtu ranged from a low of $1.74 to a high of $23.86.
We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable.
Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable.
If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production and repairs to resume operations.
Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production and repairs to resume operations.
The demand for skilled workers in our industry is high, and the supply is limited. 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 Mexico employees could result in a reduction of our labor force, increases in the wage rates that we will have to pay, or both.
Unless production is established as required by the leases covering the undeveloped acres, the leases for such acreage may expire. Our drilling plans for areas not held by production are subject to change based upon various factors. As of December 31, 2022, approximately 51% of our net acreage was undeveloped acres. See Items 1 and 2.
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.
In 2022, we hired a Director of ESG who is responsible for driving our sustainability initiatives, engaging with stakeholders, benchmarking our ESG data, and evaluating potential and emerging ESG drivers.
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.
We are subject to the FCPA and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business.
Foreign Corrupt Practices Act (the “FCPA”) and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business.
Our borrowing base under the Bank Credit Facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values.
We are required to comply with certain debt covenants and certain financial ratios under the Bank Credit Facility. Our borrowing base under the Bank Credit Facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values.
If, due to a redetermination of our borrowing base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency.
Such borrowing base determines the amount which is available under our Bank Credit Facility. If, due to a redetermination of our borrowing base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency.
(the “Issuer”), 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 “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 production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area. Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, the U.S.
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.
As we carry out our drilling program, we may not serve as operator of all planned wells. 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 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.
The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others: • changes in the supply of and demand for oil and natural gas; • market uncertainty; • level of consumer product demands; • 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; • political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia, South America and Africa; • Russia’s ongoing war in Ukraine and resulting sanctions in response thereto; 39 Table of Contents • the occurrence or threat of epidemic or pandemic diseases, such as the outbreak of COVID-19, or any government response to such occurrence or threat; • actions by OPEC Plus relating to oil and natural gas price and production controls; • 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; • the level of global oil and natural gas inventories; • localized supply and demand fundamentals and transportation availability; • 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 domestic and foreign economic conditions.
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.
Furthermore, as CCS may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO 2 emissions are intended to be captured, there may be organized opposition to CCS, including as it relates to our projects.
Furthermore, as CCS may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO 2 emissions are intended to be captured, there may be organized opposition to CCS, including as it relates to our projects. We can provide no assurance that we will be able to execute our CCS business strategy in the future.
Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collisions and adverse weather and sea conditions, including the effects of hurricanes. 53 Table of Contents In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for containment and oil removal costs and a variety of public and private damages, including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill.
In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for containment and oil removal costs and a variety of public and private damages, including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill.

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Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeThe lawsuit was dismissed during the third quarter of 2021, and the plaintiffs have appealed the dismissal to the Delaware Supreme Court. 68 Table of Contents On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against 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.
Biggest changeAs 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.
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 plaintiffs’ motion to re-open.
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.
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, subsequently, 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.
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.
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.
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 and in the third lawsuit on February 16, 2023.
In 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.
In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in two of the three Jefferson Parish Coastal Zone Management lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed.
In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in these three lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed.
Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies for more information. Item 4. Mine Saf ety Disclosures Not applicable. 69 Table of Contents PART II
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
Removed
On March 23, 2022, the Company entered into a settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims in the litigation.
Added
Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor of Mr.
Removed
On May 29, 2020, a lawsuit was filed in the Court of Chancery asserting derivative and class action claims against us relating to the ILX and Castex Acquisition. Specifically, the lawsuit relates to the fairness of the consideration paid for such acquisitions in light of the fact that certain of the sellers are our affiliates.
Added
Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023, which was denied on January 26, 2024.
Added
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
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.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

5 edited+4 added−1 removed3 unchanged
Biggest changeThe 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 May 10, 2018 through December 31, 2022. The graph assumes that $100 was invested in our common stock and each index on May 10, 2018 and that dividends were reinvested.
Biggest changeThe 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.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt — Limitation on Restricted Payments Including Dividends for additional information. Securities Authorized for Issuance Under Equity Compensation Plans See Item 12.
See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt — Limitation on Restricted Payments Including Dividends for additional information. Securities Authorized for Issuance Under Equity Compensation Plans See Part III, Item 12.
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, 2023, there were approximately 282 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 21, 2024, there were approximately 180 holders of record of our common stock.
Exploration & Production Index $ 100 $ 71 $ 78 $ 53 $ 93 $ 147 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 $ 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.
“Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding securities authorized for issuance under equity compensation plans. 70 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.
As 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.
Removed
May 10, 2018 2018 2019 2020 2021 2022 Talos Energy Inc. $ 100 $ 45 $ 83 $ 23 $ 27 $ 52 S&P 500 Index $ 100 $ 93 $ 123 $ 145 $ 187 $ 153 Dow Jones U.S.
Added
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding securities authorized for issuance under equity compensation plans. Purchases of Equity Securities by the Issuer and Affiliated Purchasers Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits.
Added
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.
Added
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.
Added
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.

Item 7. Management's Discussion & Analysis

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

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Biggest changeCash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. 79 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): Year Ended December 31, 2022 2021 Change Revenues: Oil $ 1,365,148 $ 1,064,161 $ 300,987 Natural gas 227,306 130,616 96,690 NGL 59,526 49,763 9,763 Total revenues $ 1,651,980 $ 1,244,540 $ 407,440 Total Production Volumes: Oil (MBbls) 14,561 16,159 (1,598 ) Natural gas (MMcf) 32,215 32,795 (580 ) NGL (MBbls) 1,793 1,875 (82 ) Total production volume (MBoe) 21,723 23,500 (1,777 ) Daily Production Volumes by Product: Oil (MBblpd) 39.9 44.3 (4.4 ) Natural gas (MMcfpd) 88.3 89.8 (1.5 ) NGL (MBblpd) 4.9 5.1 (0.2 ) Total production volume (MBoepd) 59.5 64.4 (4.9 ) Average Sale Price per Unit: Oil (per Bbl) $ 93.75 $ 65.86 $ 27.89 Natural gas (per Mcf) $ 7.06 $ 3.98 $ 3.08 NGL (per Bbl) $ 33.20 $ 26.54 $ 6.66 Price per Boe $ 76.05 $ 52.96 $ 23.09 Price per Boe (including realized commodity derivatives) $ 56.46 $ 40.61 $ 15.85 The information below provides an analysis of the change in our oil, natural gas and NGL revenues, due to changes in sales prices and production volumes (in thousands): Price Volume Total Revenues: Oil $ 406,231 $ (105,244 ) $ 300,987 Natural gas 98,998 (2,308 ) 96,690 NGL 11,939 (2,176 ) 9,763 Total revenues $ 517,168 $ (109,728 ) $ 407,440 Volumetric Analysis — Production volumes decreased by 4.9 MBoepd to 59.5 MBoepd for the year ended December 31, 2022.
Biggest changeCash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. 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.
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 all of the deferred tax assets will not be realized.
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.
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.
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.
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. 77 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. 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.
As a result of the derivative contracts we have on our anticipated production volumes through December 2024, 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 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.
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 12 — 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 14 — Commitments and Contingencies .
(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 12 — 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.
We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2022. The U.S.
We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2023. The U.S.
Exhibits and Financial Statement Schedules — Note 7 — Debt . 12.00% Second-Priority Senior Secured Notes—due January 2026 — The 12.00% Notes were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the “Parent Guarantor”); Talos Production Inc.
Exhibits and Financial Statement Schedules — Note 8 — Debt . 12.00% Second-Priority Senior Secured Notes—due January 2026 — The 12.00% Notes were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the “Parent Guarantor”); Talos Production Inc.
Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies . This was partially offset by a $1.6 million loss on extinguishment of debt as a result of the redemption of the 12.00% Notes further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt .
Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies . This was partially offset by a $1.6 million loss on extinguishment of debt as a result of the redemption of the 12.00% Notes further discussed in Part IV, Item 15.
The OCSLA and its implementing regulations call for two subsequent drafts, a Proposed Program (“PP”), which is open for public comment for a period of at least 90 days, and then a Proposed Final Program, which is submitted to Congress and the President for 60 days before implementation.
The OCSLA and its implementing regulations call for two subsequent drafts, a Proposed Program (“PP”), which is open for public comment for a period of at least 90 days, and then a PFP, which is submitted to Congress and the President for 60 days before implementation.
This section of this Annual Report generally discusses 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are not included in this Annual Report can be found in “Part II, Item 7.
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.
The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material restricted subsidiaries that guarantees the Issuer’s senior reserve-based revolving credit facility (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”).
The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material restricted subsidiaries that guarantees the Issuer’s Bank Credit Facility (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”).
The expense of $272.2 million for the year ended December 31, 2022 consisted of $425.6 million in cash settlement losses offset by $153.4 million in non-cash gains from the increase in the fair value of our open derivative contracts.
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.
Our Business We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the U.S. and offshore Mexico both through Upstream and the development of CCS opportunities.
Our Business We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the U.S. and offshore Mexico both through Upstream and the development of low carbon solutions opportunities.
Additionally, in August 2021, the BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets.
In August 2021, BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets.
Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing.
Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations.
The decrease in production volumes was primarily due to the third party downtime for the HP-I dry-dock in our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting HP-I and Green Canyon 18 Field and the Shell Odyssey Pipeline shut-in primarily impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 3.5 MBoepd of deferred production.
Additionally, production volumes increased due to the third party downtime for the HP-I dry-dock in our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting HP-I and Green Canyon 18 Field and the Shell Odyssey Pipeline shut-in primarily impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 3.5 MBoepd of deferred production during 2022.
See additional information on the valuation allowance as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 9 — 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 12 — Commitments and Contingencies .
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 .
The following table presents a breakout of each revenue component: Year Ended December 31, 2022 2021 2020 Oil 83 % 86 % 88 % Natural gas 14 % 10 % 9 % NGL 4 % 4 % 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.
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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021 filed on February 25, 2022.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC.
Exhibits and Financial Statement Schedules — Note 11 — Related Party Transactions for additional information. 82 Table of Contents Other (Income) Expense — During the year ended December 31, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15.
Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments for additional information. Other (Income) Expense — During the year ended December 31, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15.
The indenture governing the EnVen Second Lien Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15 th and October 15 th of each year. For additional details on the EnVen Second Lien Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt .
The indenture governing the 11.75% Notes required the redemption of $15.0 million of the principal amount outstanding at par value on April 15 th and October 15 th of each year. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt .
Sustained levels of high inflation could likely cause the Fed and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business.
Sustained levels of high inflation could likely cause the Fed and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business. In 2022 and 2023, the Fed raised its benchmark interest rate 11 times.
Equity Method Investment Income — During the year ended December 31, 2022, we recorded a $15.3 million gain on partial sale of our equity method investment in Bayou Bend offset by equity losses of $1.1 million. See Part IV, Item 15.
During the year ended December 31, 2022, we recorded a $13.9 million gain on the partial sale and $1.4 million gain on the funding of the capital carry of our equity method investment in Bayou Bend offset by equity losses of $1.1 million. See Part IV, Item 15.
The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. 88 Table of Contents The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects.
Furthermore, the Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects.
Year Ended December 31, 2022 2021 2020 Oil: NYMEX WTI high per Bbl $ 114.84 $ 81.48 $ 57.52 NYMEX WTI low per Bbl $ 76.44 $ 52.01 $ 16.55 Average NYMEX WTI per Bbl $ 94.79 $ 67.99 $ 39.16 Average oil sales price per Bbl (including commodity derivatives) $ 68.40 $ 49.67 $ 47.36 Average oil sales price per Bbl (excluding commodity derivatives) $ 93.75 $ 65.86 $ 37.09 Natural Gas: NYMEX Henry Hub high per MMBtu $ 8.81 $ 5.51 $ 2.61 NYMEX Henry Hub low per MMBtu $ 4.38 $ 2.62 $ 1.63 Average NYMEX Henry Hub per MMBtu $ 6.42 $ 3.91 $ 2.03 Average natural gas sales price per Mcf (including commodity derivatives) $ 5.30 $ 3.11 $ 2.00 Average natural gas sales price per Mcf (excluding commodity derivatives) $ 7.06 $ 3.98 $ 1.87 NGLs: NGL realized price as a % of average NYMEX WTI 35 % 39 % 25 % 78 Table of Contents 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, 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.
The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and collaborative arrangement opportunities, among others.
The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and collaborative arrangement opportunities, among others. Outlook We operate within an industry sector directly impacted by the energy transition.
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, 2022 2021 Lease operating expenses $ 308,092 $ 283,601 Lease operating expenses per Boe $ 14.18 $ 12.07 Total lease operating expenses for the year ended December 31, 2022 increased by approximately $24.5 million, or 9%.
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%.
For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — 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, 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.
The 2016 NTL was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, this NTL.
The 2016 NTL was first paused under the Trump Administration, and then in 2020, rescinded by BOEM.
Outer Continental Shelf. 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.
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.
If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. During 2022, 2021 and 2020 our ceiling test computations for our U.S. oil and gas properties resulted in a write down of nil, nil and $267.9 million, respectively.
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.
BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM. Deepwater Operations — We have interests in Deepwater fields in the U.S. Gulf of Mexico.
BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM.
Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see please see Part IV, Item 15.
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.
As of December 31, 2022, we believe it is more likely than not that some or all of the benefits from our federal and state deferred tax assets will not be realized and reduced the net federal and state deferred tax assets by a valuation allowance.
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.
The 12.00% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes mature on January 15, 2026 and have interest payable semi-annually each January 15 and July 15. We made an interest payment of $38.7 million on January 17, 2023.
The 12.00% 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 12.00% Notes were scheduled to mature on January 15, 2026 and had interest payable semi-annually each January 15 and July 15.
Our management has identified the following critical accounting estimates. Our significant accounting policies are described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies . Oil and Natural Gas Properties — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities.
Our management has identified the following critical accounting estimates. Our significant accounting policies are described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies .
During January 1, 2022 through December 31, 2022, the daily spot prices for NYMEX WTI crude oil ranged from a high of $123.64 per Bbl to a low of $71.05 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.85 per MMBtu to a low of $3.46 per MMBtu.
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.
Moreover, the 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 liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements.
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.
See Part IV, Item 15. 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.
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 2 — Summary of Significant Accounting Policies . Interest Expense — During the year ended December 31, 2022, we recorded $125.5 million of interest expense compared to $133.1 million during the year ended December 31, 2021.
Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies . Interest Expense — During the year ended December 31, 2023, we recorded $173.1 million of interest expense compared to $125.5 million during the year ended December 31, 2022.
Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010.
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.
We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, we also utilize our expertise to explore opportunities to reduce industrial emissions through our CCS initiatives along the Gulf Coast.
We leverage decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. We are also utilizing our expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.
Additionally, it includes a $15.3 million gain for the year ended December 31, 2022 on partial sale of our investment in Bayou Bend that is further discussed Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Related Party Transactions .
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 .
The IRA 2022 reinstates Lease Sale 257 held in November 2021, and requires the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders.
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 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 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.
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 replace, remove or retire the associated assets.
The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.
Eugene Island Pipeline System — During the first quarter of 2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the Eugene Island Pipeline System, which carries our production from the Phoenix Field and Green Canyon 18 Field.
We estimate the shut-in resulted in deferred production of approximately 0.7 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in. 64 Table of Contents Eugene Island Pipeline System — During the first quarter of 2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the Eugene Island Pipeline System, which carries our production from the Phoenix Field and Green Canyon 18 Field.
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. Hurricanes and Tropical Storms — Since our operations are in the U.S.
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.
The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.
During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.
Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. The estimates of proved reserves are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions.
Prices are determined using SEC pricing. 78 Table of Contents Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. The estimates of proved reserves are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data.
We define these as the following: • EBITDA — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense. • Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense. 83 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, 2022 2021 2020 Net income (loss) $ 381,915 $ (182,952 ) $ (465,605 ) Interest expense 125,498 133,138 99,415 Income tax expense (benefit) 2,537 (1,635 ) 35,583 Depreciation, depletion and amortization 414,630 395,994 364,346 Accretion expense 55,995 58,129 49,741 EBITDA 980,575 402,674 83,480 Write-down of oil and natural gas properties — 18,123 267,916 Transaction and other (income) expense (1) (34,513 ) 5,886 14,917 Decommissioning obligations (2) 31,558 21,055 — Derivative fair value (gain) loss (3) 272,191 419,077 (87,685 ) Net cash received (paid) on settled derivative instruments (3) (425,559 ) (290,164 ) 143,905 (Gain) loss on debt extinguishment 1,569 13,225 (1,662 ) Non-cash write-down of other well equipment inventory — 5,606 699 Non-cash equity-based compensation expense 15,953 10,992 8,669 Adjusted EBITDA $ 841,774 $ 606,474 $ 430,239 (1) 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.
We define these as the following: • EBITDA — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense. • Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense. 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.
Exhibits and Financial Statement Schedules — Note 7 — Debt . EnVen’s 11.75% Senior Secured Second Lien Notes—due April 2026 — On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “EnVen Second Lien Notes”) with a principal amount of $257.5 million.
The 12.00% Notes were redeemed on February 7, 2024 for $662.4 million utilizing the net proceeds from the Debt Offering. 11.75% Senior Secured Second Lien Notes—due April 2026 — On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount of $257.5 million.
For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. Recently Adopted Accounting Standards None. Recently Issued Accounting Standards There were no recently issued accounting standards material to us.
For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. Determination of Fair Value in Business Combinations — We account for business combinations under the acquisition method of accounting.
The EnVen Second Lien Notes will mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15 th and October 15 th of each year.
The 11.75% Notes were scheduled to mature on April 15, 2026 and interest accrued and was paid semi-annually in cash in arrears on April 15 th and October 15 th of each year.
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, 2022 2021 Depreciation, depletion and amortization $ 414,630 $ 395,994 Depreciation, depletion and amortization per Boe $ 19.09 $ 16.85 Depreciation, depletion and amortization expense for the year ended December 31, 2022 increased by approximately $18.6 million, or 5%.
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%.
Based on our current level of legacy operations, the recently acquired EnVen 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 2023 Upstream capital spending program of $650.0 million to $675.0 million as well as expected investments in our CCS operating segment of $70.0 million to $90.0 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 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.
At December 31, 2022, the Company’s ceiling test computation was based on SEC pricing of $96.03 per Bbl of oil, $6.80 per Mcf of natural gas and $33.89 per Bbl of NGLs. 75 Table of Contents 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.
Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands): Year Ended December 31, 2022 2021 Operating activities $ 709,739 $ 411,388 Investing activities $ (311,977 ) $ (293,747 ) Financing activities $ (423,469 ) $ (82,022 ) Operating Activities — Net cash provided by operating activities increased $298.4 million in 2022 compared to 2021 primarily attributable to an increase in revenues net of lease operating expense of $382.9 million.
Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands): Year Ended December 31, 2023 2022 Operating activities $ 519,069 $ 709,739 Investing activities $ (512,626 ) $ (311,977 ) Financing activities $ 85,411 $ (423,469 ) Operating Activities — Net cash provided by operating activities decreased $190.7 million in 2023 compared to 2022 primarily attributable to a decrease in revenues combined with an increase in lease operating expense of $275.6 million. 75 Table of Contents Investing Activities — Net Cash used in investing activities increased $200.6 million in 2023 compared to 2022 primarily due to an increase in capital expenditures of $238.3 million.
Other Operating Expense — During the year ended December 31, 2022, we recorded $31.6 million of estimated decommissioning obligations primarily 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.
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.
Significant impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs. 76 Table of Contents Five-Year Offshore Oil and Gas Leasing Program Update — Under the OCSLA, as amended, the 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.
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.
(2) Excludes $2.7 million of expenditures reflected as “Other operating (income) expense” on the Consolidated Statements of Operations. (3) 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.
(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.
Risk Factors. 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.
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.
Overview of Debt Instruments Financing Arrangements — As of December 31, 2022, total debt, net of discount and deferred financing costs, was approximately $585.3 million, comprised of our $638.5 million aggregate principal amount of the 12.00% Notes and no outstanding borrowings under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2022.
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.
We were one of the most active bidders in Lease Sale 257 and we were the high bidder on 10 blocks and awarded leases on 9 blocks. Furthermore, the DOI must hold Gulf of Mexico lease sales 259 and 261 by March 31, 2023, and September 30, 2023, respectively.
We were one of the most active bidders in Lease Sale 257 and we were the high bidder on ten (10) blocks and awarded leases on nine (9) blocks.
The expense of $419.1 million for the year ended December 31, 2021 consisted of $290.2 million in cash settlement losses and $128.9 million in non-cash losses from the decrease in the fair value of our open derivative contracts.
The income of $80.9 million for the year ended December 31, 2023 consisted of $90.4 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $9.5 million in cash settlement losses.
We estimate the shut-in resulted in deferred production of approximately 0.7 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in.
For the year ended December 31, 2022, we estimate the shut-in has resulted in deferred production of approximately 1.2 MBoepd based on production rates prior to the shut-in. Known Trends and Uncertainties Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile.
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, 2022 2021 General and administrative expense $ 99,754 $ 78,677 General and administrative expense for the year ended December 31, 2022, increased by approximately $21.1 million, or 27%.
The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data): Year Ended December 31, 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%.
Price Risk Management Activities — Price risk management activities for year ended December 31, 2022 resulted in a decrease of approximately $146.9 million, or 35%.
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%.
Our hedging strategy and future hedging transactions will be determined in accordance with both our Bank Credit Facility and Hedging Policy and may be different from what we have done on a historical basis.
Our hedging strategy and future hedging transactions will be determined in accordance with both our Bank Credit Facility and Hedging Policy and may be different from what we have done on a historical basis. 68 Table of Contents Expenses Lease Operating Expense — Lease operating expense consists of the daily costs incurred to bring oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain our producing properties.
Guarantor Financial Information — We own no operating assets and have no operations independent of our subsidiaries.
The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1. Guarantor Financial Information — We own no operating assets and have no operations independent of our subsidiaries.
The information below provides the financial results and an analysis of significant variances in these results (in thousands): Year Ended December 31, 2022 2021 Write-down of oil and natural gas properties $ — $ 18,123 Accretion expense $ 55,995 $ 58,129 Other operating expense $ 33,902 $ 32,037 Interest expense $ 125,498 $ 133,138 Price risk management activities expense $ 272,191 $ 419,077 Equity method investment income $ 14,222 $ — Other (income) expense $ (31,800 ) $ 6,988 Income tax (benefit) expense $ 2,537 $ (1,635 ) Write-Down of Oil and Natural Gas Properties — Due to our non-consent to the Block 31 appraisal program, we recorded an impairment of $18.1 million for our unproved property investment in Block 31 during the year ended December 31, 2021 as the costs were not recoverable.
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.
Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. Our working capital deficit has decreased since December 31, 2021 primarily due to a decrease of $118.2 million in liabilities from price risk management activities and an increase of $24.1 million in assets from price risk management activities.
Our working capital deficit has decreased since December 31, 2022 primarily due to a decrease of $61.1 million in liabilities from price risk management activities and an increase of $11.1 million in assets from price risk management activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information.
The decrease was partially offset by an increase of 4.2 MBoepd in deferred production attributable to Hurricane Ida in 2021. 80 Table of Contents Operating Expenses Lease Operating Expense The following table highlights lease operating expense items in total and on a cost per Boe production basis.
These increases were partially offset by a decrease of 13.4 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field. 70 Table of Contents Operating Expenses Lease Operating Expense The following table highlights lease operating expense items in total and on a cost per Boe production basis to our Upstream Segment.
Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies for additional information on decommissioning obligations.
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 .
Despite the expectation for a below-norm hurricane season in 2023, large uncertainties remain. Significant Developments The following encompasses significant developments since our Annual Report on Form 10-K for the year ended December 31, 2021: EnVen Acquisition — On September 21, 2022, we executed a merger agreement to acquire EnVen, a private operator in the Deepwater U.S.
Significant Developments The following encompasses significant developments since the filing of our Annual Report on Form 10-K for the year ended December 31, 2022: QuarterNorth Acquisition — On January 13, 2024, we executed the QuarterNorth Merger Agreement to acquire QuarterNorth, a privately-held U.S Gulf of Mexico exploration and production company.
We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances.
Historically, we have funded significant acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.
Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $3.9 million. Letters of credit that are outstanding reduce the available revolving credit commitments. For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies .
Gulf of Mexico and certain obligations under the PSCs with Mexico from third party sureties. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments.
The change is primarily a result of the interest associated with the Bank Credit Facility with no outstanding borrowings as of December 31, 2022 when compared to $375.0 million as of December 31, 2021. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt .
The change is primarily a result of the increase in interest associated with the 11.75% Notes assumed as part of the EnVen Acquisition. Additionally, there was an increase in interest associated with the Bank Credit Facility due to increased interest rates and average borrowings when compared to the same period in 2022. See further discussion in Part IV, Item 15.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

8 edited+2 added−0 removed7 unchanged
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 7 — Debt , included elsewhere in this Annual Report.
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.
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, 2022, our interest rate risk exposure is mitigated as a result of fixed interest rates on 100% of our debt.
We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. As of December 31, 2023, our interest rate risk exposure is mitigated as a result of fixed interest rates on 81% 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, 2022, our average oil price realizations after the effect of derivatives increased 38% to $68.40 per Bbl from $49.67 per Bbl in the comparable 2021 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, 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.
Our average natural gas price realizations after the effect of derivatives increased 70% during the year ended December 31, 2022 to $5.30 per Mcf from $3.11 per Mcf in the comparable 2021 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 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. 91 Table of Contents We had commodity derivative instruments in place to reduce the price risk associated with future production of 9,537 MBbls of crude oil and 18,764 MMBtu of natural gas at December 31, 2022, with a net derivative liability position of $43.4 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. 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.
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 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.
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, 2022 (in thousands): Oil and Natural Gas Derivatives Ten Percent Increase Ten Percent Decrease Fair Value Fair Value Change Fair Value Change Price impact (1) $ (43,359 ) $ (117,556 ) $ (74,197 ) $ 30,778 $ 74,137 (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, 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.
Variable Interest Rate Risks We had total debt outstanding of $638.5 million at December 31, 2022, before unamortized original issue discount and deferred financing costs, from our 12.00% Notes, which bears interest at a fixed rate. There were no outstanding borrowings under our Bank Credit Facility with variable interest rates.
Variable Interest Rate Risks We had total debt outstanding of $1,066.0 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.
Added
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%.
Added
Exhibits and Financial Statement Schedules — Note 8 — Debt , included elsewhere in this Annual Report.

Other TALO 10-K year-over-year comparisons