10-K/A

如果註冊人是《證券法》第405條所定義的知名經驗豐富的發行人，則通過勾選標記進行驗證。是 ☑ No

如果註冊人無需根據該法案第13或15（d）條提交報告，則通過勾選標記進行驗證。是的 No ☑

通過勾選標記確定註冊人是否：（1）在過去12個月內（或在註冊人被要求提交此類報告的較短期限內）提交了1934年證券交易法第13或15（d）條要求提交的所有報告，以及（2）在過去90天內是否遵守此類提交要求。是 ☑ No

通過勾選標記檢查註冊人是否已在過去12個月內（或在註冊人被要求提交此類文件的較短期限內）以電子方式提交了根據S-t法規第405條（本章第232.405條）要求提交的所有交互數據文件。是 ☑ No

通過複選標記來確定註冊人是大型加速申報人、加速申報人、非加速申報人、小型報告公司還是新興成長型公司。請參閱《交易法》第120條第2條中「大型加速申報人」、「加速申報人」、「小型報告公司」和「新興成長型公司」的定義。

如果是新興成長型公司，請通過勾選標記表明註冊人是否選擇不利用延長的過渡期來遵守根據《交易法》第13（a）條規定的任何新的或修訂的財務會計準則。☐

通過勾選標記檢查註冊人是否已提交報告並證明其管理層根據《薩班斯-奧克斯利法案》（15 U.S.C.）第404（b）條對其財務報告內部控制有效性的評估7262（b））由編制或發布審計報告的特許會計師事務所執行。 ☑

如果證券是根據該法案第12（b）條登記的，請通過勾選標記表明文件中包含的登記人的財務報表是否反映了對先前發布的財務報表錯誤的更正。 ☐

通過勾選標記來驗證這些錯誤更正是否是需要根據§240.10D-1（b）對註冊人的任何高管在相關恢復期內收到的激勵性補償進行恢復分析的重述。☐

通過勾選標記檢查註冊人是否是空殼公司（定義見該法案第120條第2款）。 YEs☐ 沒有預設

登記人非關聯公司持有的有投票權和無投票權普通股的總市值，基於2023年6月30日紐約證券交易所普通股股票的收盤價，是美金1,493,763,437.

Talos Energy Inc.表格10-k年度報告的第1號修正案（本「表格10-K/A」）(the「公司」、「我們」、「我們的」或「我們」）截至2023年12月31日的財年，最初於2024年2月29日向美國證券交易委員會（「SEC」）提交（「原始文件」），現提交以反映以下內容：

Certain factors may have a material adverse effect on our business, financial condition, and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Annual Report, including our Consolidated Financial Statements and related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occur, our business, financial condition, results of operations and future prospects could be materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.

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 revenues, cash flows, profitability and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, and the risk that we are required to write-down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can economically produce. A reduction in production and/or the prices we receive for our production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. 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. Subsequent to December 31, 2023, NYMEX WTI crude oil and NYMEX Henry Hub natural gas prices recorded daily lows of $70.62 per Bbl and $1.61 per MMBtu, respectively.

The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because oil, natural gas and NGLs accounted for approximately 73%, 20%, and 7%, respectively, of our estimated proved reserves as of December 31, 2023, and approximately 75%, 18%, and 7%, respectively, of our 2023 production on an MBoe basis, our financial results are sensitive to movements in oil, natural gas and NGL prices.

Future exploration and drilling results are uncertain and involve substantial costs.

Drilling for oil and natural gas involves numerous risks including the risk that we may not encounter commercially productive reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

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 such, the success and profitability of our operations may be disproportionately exposed to the effect of regional conditions such as:

Because all or a number of our properties could experience many of the same conditions at the same time, these conditions may have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

Production periods or relatively short reserve lives for U.S. Gulf of Mexico properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

Substantially all of our operations are in the U.S. Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other companies with longer-life reserves in other producing areas. Our future oil and natural gas production is highly dependent upon finding and/or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.

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. 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. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, current market conditions may adversely impact our ability to obtain financing to fund acquisitions, and further lower the level of activity and depressed values in the oil and natural gas property sales market.

Our actual recovery of reserves may substantially differ from our proved reserve estimates.

Reserve estimation is a subjective and complex process that requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data to estimate volumes to be recovered from underground accumulations of oil and natural gas that cannot be directly measured. 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. Our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

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. 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. 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, 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. Further, actual future net revenues are affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties affects the timing of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and natural gas industry in general.

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. Furthermore, any or all of our undeveloped and developed non-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling or waterflood operations. Our reserve estimates include the assumptions that we incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. 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. If commodity prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.

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. 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. On the acreage that we do not operate, we have less control over the timing of drilling, and therefore there is additional risk of expirations occurring in those acreages.

The marketability of our production depends mostly upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities.

The marketability of our production depends upon the availability, proximity, operation and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of this infrastructure could result in the shut-in of producing wells or delays or discontinuance of development plans for our properties. The disruption of these gathering systems, pipelines and processing facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. Federal, state, and local regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors change dramatically, the financial impact could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.

Inflationary issues and associated changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.

The U.S. inflation rate steadily rose in 2021 and into 2022 before eventually declining throughout 2023. These inflationary pressures resulted in increases to the costs of our goods, services and personnel, which in turn, caused our capital expenditures and operating costs to rise. The U.S. Federal Reserve (the “Fed”) and other central banks increased interest rates multiple times in 2022 and 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S. and globally. While the Fed indicated in December 2023 that it may reduce benchmark interest rates in 2024, the continuation of elevated rates could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business.

Higher crude oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation or the monetary policies in response thereto.

We may be unable to pursue our CCS business, either wholly or in significant measure, which could have a material adverse effect on our business, results of operations and financial condition.

The successful development of our CCS projects is dependent on various economic, regulatory, operational and technical factors. The failure to satisfy, wholly or in significant measure, any of such factors could have a material adverse impact on our business, results of operations and financial condition.

The availability and applicability of various federal financial incentives related to our projects is uncertain and there is no assurance that if available, such incentives would be adequate for our CCS project needs or that such incentives will continue to be available in the future.

Additionally, successful development of CCS projects in the United States requires us to comply with stringent and varied regulatory schemes requiring permits applicable to subsurface injection of CO2 for geologic sequestration. 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. 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. 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. 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 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.

CCS projects also require satisfying certain operational factors, such as locating a suitable source of anthropogenic CO2 and reaching suitable agreements to capture that CO2. 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 CO2. Not all emission sources produce sufficiently large quantities of pure or relatively pure streams of CO2, or have installed equipment to capture such CO2, so as to be usable in one or more of our CCS projects. As a result, we may not be able to obtain sufficient quantities of CO2 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. Additionally, development of successful CCS projects will require infrastructure to transport CO2 between the source and our CCS sites. In project areas with existing CO2 transportation pipelines, this may require reaching an agreement on CO2 transportation with operators of CO2 pipelines within the regions in which we operate. Inability to reach a suitable agreement may render a project uneconomic or impracticable.

Separately, if no CO2 pipelines exist in proposed project areas, or if existing pipelines do not extend to one or more of our project sites, we may be required to convert existing pipelines, or build new CO2 pipelines or lateral connections, which may be subject to various environmental and other permitting requirements to include increased regulation from U.S. federal and state agencies, as well as third party easements, which may render one or more projects uneconomical. We will also need to build the required equipment on a timely basis and at a cost that is economically viable. Additionally, complex recordkeeping and GHG emissions/sequestration accounting may be required in connection with one or more of our projects, which may increase the costs of such operations. Different methodologies may be required for various regulatory and non-regulatory accounts regarding GHG emissions/sequestration at one or more of our projects, including but not limited to, compliance with the EPA’s mandatory Greenhouse Gas Reporting Program. Furthermore, as CCS may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO2 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. Any failure by us to achieve such expectations in whole or any significant measure could have a material adverse effect on our business, results of operations and financial condition.

Our inability to benefit from Section 45Q tax credits could materially reduce our ability to develop CCS projects and, as a result, may adversely impact our business, results of operations and financial condition.

The successful development of our CCS projects is dependent upon our ability to benefit from certain financial and tax incentives available with respect to CCS projects. The development of CCS projects is incentivized by tax credits provided under Section 45Q of the Internal Revenue Code of 1986, as amended (such credits, “Section 45Q tax credits”), which provides a tax credit for qualified CO2 that is captured using carbon capture equipment and disposed of in secure geological storage. The amount of Section 45Q tax credits from which we may benefit is dependent upon our ability to satisfy certain wage and apprenticeship requirements, which we cannot assure you that we will satisfy. With respect to the first five tax years a qualifying CCS project is in service, but not beyond December 31, 2032, we may elect a “direct pay” option with respect to available Section 45Q tax credits to efficiently monetize their value (i.e., we may receive a payment for the tax credits through a tax refund as if there had been an overpayment of taxes). Following the period in which the direct pay election is available and for the remaining period in which the applicable Section 45Q tax credits are otherwise available, we may elect to transfer the Section 45Q tax credits to unrelated taxpayers. We cannot assure you that we will be able to efficiently monetize Section 45Q tax credits that are transferred to unrelated taxpayers. We will benefit from Section 45Q tax credits only if we satisfy the applicable statutory and regulatory requirements for obtaining the Section 45Q tax credits, including that we own carbon capture equipment that captures qualified CO2 that we physically or contractually capture and securely store, or if another party that owns carbon capture equipment elects to pass through Section 45Q tax credits to us, that we dispose of the qualified CO2 in secure storage. If we are unable to satisfy such statutory and regulatory requirements or otherwise qualify for or obtain the Section 45Q tax credits, our CCS projects may no longer be economically viable and may not be completed. We cannot assure you that we will be successful in satisfying such requirements or otherwise qualifying for or obtaining the Section 45Q tax credits currently available or that we will be able to effectively benefit from such tax credits. Section 45Q tax credits are also subject to recapture with respect to any CO2 that ceases to be disposed of in secure storage, which recapture is treated as an increase in tax liability for the year in which the recapture occurs. The recapture period for Section 45Q tax credits is limited to a 3-year lookback period preceding the date that sequestered CO2 escapes from its secure storage.

Additionally, the availability of Section 45Q tax credits may be reduced, modified or eliminated as a matter of legislative or regulatory policy. There can be no assurance that Section 45Q tax credits will not be reduced, modified or eliminated in the future, including as a result of any change in presidential administration as a result of the 2024 U.S. presidential election. Any such reduction, modification or elimination of Section 45Q tax credits, or our inability to otherwise benefit from Section 45Q tax credits, could materially reduce our ability to develop CCS projects and, as a result, may adversely impact our business, results of operations and financial condition. Even if we are able to benefit from Section 45Q tax credits, we may determine that additional financial incentives are required for our CCS projects to be economically viable. If such additional incentives do not emerge, we may not be able to achieve an economic return from our CCS business or, alternatively, the construction or operation of our CCS projects may be substantially delayed, unprofitable or otherwise infeasible.

We may be unable to provide the financial assurances in the amounts and under the time periods required by BOEM if it submits future demands to cover our decommissioning obligations. 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.

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. 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. 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 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, 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. 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. 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. Notwithstanding the above, BOEM, now under the Biden Administration, could, in the future, continue to make new demands for additional financial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities.

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. BOEM has the right to issue financial assurance orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements.

In the event that BOEM finalizes new regulations similar to or more stringent than the 2016 NTL, such as BOEM’s June 2023 proposed rule that substantially revises the supplemental financial assurance requirements applicable to offshore oil and gas operations, the surety bond market has very limited capacity to provide additional financial assurance and we therefore may not be able to procure and provide the financial assurance required by such new regulations. 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. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations, reduced cash flows if unable to comply and consequently have a material adverse effect on our business and results of operations.

See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS.

Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptions.

As an oil and gas producer, we have various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business. In particular, the implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls are sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. 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. Any future terrorist attack at our facilities, or those of our purchasers or vendors, could have a material adverse effect on our financial condition and operations.

Global geopolitical tensions may create heightened volatility in oil, gas and NGL prices and could adversely affect our business, financial condition and results of operations.

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. The upcoming presidential election in the U.S., the expected change in presidential administration in Mexico, the extended war between Russia and Ukraine and increasing hostilities in the Middle East may cause prolonged uncertainty and volatility in commodity prices.

Mexico’s most recent presidential election was held in July 2018. Presidential reelection is not permitted in Mexico. President Andrés Manuel López Obrador, took office on December 1, 2018, and his successor is due to be elected in June of 2024. At this time we cannot predict what changes (if any) will result from this change in administration. Political events in Mexico could adversely affect economic conditions and/or the oil and gas industry and, by extension, our results of operations and financial position.

On February 24, 2022, Russian military forces invaded Ukraine, and sustained war and continued and prolonged disruption in the region is likely.

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:

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. The situation is rapidly evolving as a result of the war in Ukraine, and the U.S., the European Union, the United Kingdom and other countries may implement additional sanctions, export controls or other measures against Russia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such sanctions and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations.

We are actively monitoring the situation in Ukraine and assessing its impact on our business, including our business partners and customers. To date we have not experienced any material interruptions in our infrastructure, supplies, technology systems or networks needed to support our operations. We have no way to predict the progress or outcome of the war in Ukraine or its impacts in Ukraine, Russia or Belarus as the war, and any resulting government reactions, are rapidly developing and beyond our control. Continued hostilities, or any significant increases in the extent and duration of the military action, sanctions and resulting market disruptions — or any meaningful escalation in the objectives thereof or the methods used by the combatants to achieve such objectives —could be significant and could potentially have substantial impact on the global economy and our business for an unknown period of time.

Alternatively, a cessation of hostilities as a result of a negotiated withdrawal or otherwise—particularly if coupled with an easing of international sanctions — could cause commodity prices to decline in a manner that would reduce the revenues we receive for our oil and gas production. During the first quarter of 2022, we experienced an increase in commodity prices as sanctions imposed on Russia severely limited the access of Russian oil and gas producers to international markets. In the months that followed, commodity prices subsequently decreased and remained stagnant during the second half of 2022. If the military action concludes and the related sanctions are dropped, commodity prices could significantly decrease. Any of the above mentioned factors could affect our business, financial condition and results of operations.

Additionally, on October 7, 2023, Hamas, a U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel. On October 8, 2023, Israel formally declared war on Hamas, and the armed conflict is ongoing as of the date of this filing. Hostilities between Israel and Hamas have escalated and involved surrounding countries in the Middle East. Iranian-backed groups have launched attacks on U.S. military bases and assets in Syria, Iraq, and Jordan, and have targeted international shipping in the Red Sea. After three American troops were killed in a drone attack by an Iran-backed militant group, the U.S. launched retaliatory strikes on multiple sites in Iraq and Syria used by Iranian forces and Iran-backed militants. U.S. and British forces then launched a series of strikes on Houthi targets in Yemen in response to continuing attacks on shipping in the Red Sea and Gulf of Aden. Although the length, impact and outcome of the military conflicts between Ukraine and Russia and Israel and Hamas, respectively, are highly unpredictable, these conflicts could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions. It is not possible at this time to predict or determine the ultimate consequence of these regional conflicts. These conflicts and their broader impacts could adversely affect our business, financial condition and results of operations and the global economy.

We may not be in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves from our non-operated properties.

As we carry out our drilling program, we may not serve as operator of all planned wells. 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. We may have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners, and our limited ability to influence operations and associated costs of properties operated by others, could prevent the realization of anticipated results in drilling or acquisition activities. 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:

In addition, with respect to oil and natural gas projects that we do not operate, we have limited influence over operations, including limited control over the maintenance of safety and environmental standards. The operators of those properties may, depending on the terms of the applicable joint operating agreement:

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

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. While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

Our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our Bank Credit Facility. Our derivative agreements with the lenders are secured by the security documents executed by the parties under the Bank Credit Facility. Future collateral requirements for our commodity hedging activities are uncertain and depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions.

Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine life and endangered and threatened species.

Our oil and natural gas operations in the United States and Mexico are subject to stringent federal, state and/or local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. 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. Additionally, the threat of climate change continues to be a heightened area of focus and regulatory and disclosure requirements in the United States. For example, in March 2022, the SEC proposed rules which could require additional disclosure of climate change-related information, including, among other things, climate change risk management; short-medium-and long-term climate-related financial risks; and reporting Scope1, Scope2 and (for certain companies) Scope3 emissions. The SEC’s proposed climate disclosure rules have not yet been finalized, but implementation of the rules as proposed could impose additional costly and time-consuming requirements on our business. For additional information about government regulation related to environmental and worker safety matters, please see Part I, Items 1 and 2. Business and Properties — Government Regulation — Environmental and Occupational Safety and Health Regulations. 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.

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.

The Biden Administration has taken a number of actions that may result in stricter environmental, health and safety standards applicable to our operations and those of the oil and gas industry more generally. The Biden Administration issued the “Executive Order on Tackling the Climate Crisis at Home and Abroad” on January 27, 2021 (the “Climate Change Executive Order”). This executive order directed the Secretary of the Interior to halt indefinitely new oil and natural gas leases on federal lands and offshore waters pending completion of a review by the Secretary of the Interior of federal oil and gas permitting and leasing practices in light of the Biden Administration’s concerns regarding the impact of these activities on the environment and climate. The Secretary of the Interior completed its review of permitting and leasing practices in November 2021 and issued a report recommending, among other things, an increase in royalty rates and financial assurance requirements. However, litigation concerning the Climate Change Executive Order’s pause on new oil and gas leases is ongoing. In June 2021, the U.S. District Court for the Western District of Louisiana issued a nationwide preliminary injunction barring the Biden Administration from implementing the pause in new federal oil and gas leases, an injunction which was made permanent in August 2022. This effectively halts implementation of the leasing suspension with respect to those lease sales canceled or postponed prior to March 24, 2021. 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. 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. 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. The most recent Five-Year Leasing Program expired on June 30, 2022 and on July 1, 2022, BOEM released a proposed program for 2023 through 2028. The proposed program, which was subject to public comment through October 6, 2022, proposes no more than ten potential lease sales in the Gulf of Mexico. On September 29, 2023, the proposed final program for 2024-2029 was published and includes a maximum of three potential oil and gas lease sales in the Gulf of Mexico scheduled to be held in years 2025, 2027 and 2029. The Secretary of the Interior approved the 2024-2029 program via a combined decision memo and Record of Decision. It is likely, however, that the new Five-Year Leasing Program will be subject to heightened environmental review. It is also possible that the program could be delayed by opposing lawsuits that were filed on February 12, 2024 by the American Petroleum Institute and by Earthjustice representing multiple environmental groups both of which are challenging BOEM’s actions. Future actions taken by the Biden Administration to limit the availability of new oil and gas leases on the OCS would adversely impact the offshore oil and gas industry and impact demand for our products.

Over the past decade, BSEE and BOEM, primarily under the Obama Administration, have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. While actions by BSEE or BOEM under the Trump Administration sought to mitigate or delay certain of those more rigorous standards, the Biden Administration could reconsider rules and regulatory initiatives implemented under the previous administration and replace them with more stringent requirements and also provide more rigorous enforcement of existing regulatory requirements. For example, in August 2023, BSEE published a final rule, effective October 23, 2023, to clarify and modify certain blowout preventer system requirements. The rule requires, among other things, that the blowout preventer system is able to close and seal the wellbore at all times to the wells maximum kick tolerance design limits and includes more stringent requirements for failure reporting. Compliance with any added or more stringent regulatory requirements or enforcement initiatives and existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, governmental agencies under the Biden Administration may continue evaluating aspects of safety and operational performance in the U. S. Gulf of Mexico that may result in new, more restrictive requirements.

These regulatory actions, or any new laws, executive orders, regulations or other legal or enforcement initiatives, that impose increased costs or more stringent operational standards could delay or disrupt our operations, result in increased supplemental bonding and associated costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities or result in suspension or cancellation of leases. Also, if material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling and production operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

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. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can discharge materials and/or GHG emissions into the environment; bonds or other financial responsibility requirements to cover drilling contingencies, well P&A and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation service or the price, terms, and conditions related to the purchase and sale of oil and natural gas; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold federal leases, the federal government requires that we comply with numerous additional regulations applicable to government contractors.

The SENER has promulgated guidelines to establish procedures for conducting the unitization of shared reservoirs and approving the terms and conditions of unitization and unit operating agreements, as well as the authority to direct parties holding rights in a potentially shared reservoir to appraise and potentially form a unit for development of such reservoir.

If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online, and will be unable to predict the production levels of such wells once brought back online.

If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut-in. Any shut-in or curtailment of the oil, natural gas and NGLs produced from our fields could adversely affect our financial condition and results of operations.

We may experience significant shut-ins and losses of production due to the effects of events outside of our control, including tropical storms and hurricanes in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico and epidemics, outbreaks or other public health events.

Our production is primarily associated with our properties in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes, tropical storms, loop currents and other adverse weather conditions in the U.S. Gulf of Mexico. We are unable to predict what impact future incidents might have on our future results of operations and production.

Epidemics, pandemics, outbreaks or other public health events that are outside of our control could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees.

We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named U.S. Gulf of Mexico windstorm, oil pollution, construction risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses. See Part I, Items 1 and 2. Business and Properties – Insurance Matters for more information on our insurance coverage.

An operational or hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. 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.

We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the U.S. Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

From time to time, we may provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. 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.

Our operations are subject to numerous risks of oil and natural gas drilling and production activities.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves are found. The cost of drilling and completing wells is often uncertain. To the extent we drill additional wells in the U.S. Gulf of Mexico Deepwater and/or in the Gulf Coast deep shelf, our drilling activities increase capital cost. In addition, the geological complexity of the areas in which we have oil and natural gas operations make it more difficult for us to sustain the historical rates of drilling success. Oil and natural gas drilling and production activities may be shortened, delayed or cancelled as a result of a variety of factors, many of which are beyond our control. These factors include:

The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry holes and wells that are productive but do not produce sufficient cash flows to recoup drilling costs.

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. If an oil discharge or substantial threat of discharge were to occur, we could be liable for costs and damages, which costs and damages could be material to our results of operations and financial position.

We have an interest in Deepwater fields and may attempt to pursue additional operational activity in the future and acquire additional fields and leases in the Deepwaters of the U.S. Gulf of Mexico. 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. For example, the drilling of Deepwater wells requires specific types of drilling rigs with significantly higher day rates and limited availability as compared to the rigs used in shallower water. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the Deepwater operations generally lack the physical and oilfield service infrastructure present in the shallower waters of the U.S. Gulf of Mexico conventional shelf. As a result, a considerable amount of time may elapse between a Deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the Deepwater may never be produced economically.

If any of these industry operating risks occur, we could have substantial losses. 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. Any of these industry operating risks could have a material adverse effect on our business, results of operations and financial condition.

Competition within our industry may adversely affect our operations. Many of our competitors are larger and have more available financial resources.

The oil and gas industry is highly competitive, and many companies in our industry are larger and have substantially greater financial resources than we do. We compete with these companies for oil and natural gas leases and other properties; equipment and personnel; and marketing our product to end-users. Such competition can significantly increase costs and the availability of resources available to us, which could provide larger companies a competitive advantage. Larger competitors may also be able to more easily attract and retain experienced personnel. In addition, larger competitors may be better able to respond and adapt to adverse economic and industry conditions, including price fluctuations, reduced oil and gas demand, political changes and current and future governmental regulations and taxation.

Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to outbid us for acquisitions, productive oil and gas properties and exploratory prospects. Further, our competitors may be able to expend greater resources on the existing and changing technologies to gain competitive advantages. If we are unable to compete successfully in the future, our future revenues and growth may be diminished or restricted.

The loss of our larger customers could materially reduce our revenue and materially adversely affect our business, financial condition and results of operations.

We have a limited number of customers that provide a substantial portion of our revenue. The loss of our larger customers, including Shell Trading (US) Company and Valero Energy Corporation, could adversely affect our current and future revenue, and could have a material adverse effect on our business, financial condition and results of operations. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for additional information.

Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, which is attributable, among other reasons, to the volatility in commodity prices. Our operations are dependent upon key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have an adverse effect on us and our operations.

In addition, our exploration, production and decommissioning activities require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable depends upon our ability to employ and retain skilled workers. Our ability to expand operations depends in part on our ability to increase the size of our skilled labor force, including geologists and geophysicists, field operations managers and engineers, to handle all aspects of our exploration, production and decommissioning activities. 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. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

We have operations in multiple jurisdictions, including jurisdictions in which the tax laws, their interpretation or their administration may change. As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated. Additionally, future tax legislative or regulatory changes in the United States, Mexico or any other jurisdiction in which we operate or have subsidiaries could result in changes to the taxation of our income and operations, which could also adversely impact our after-tax profitability.

We are subject to income, withholding and other taxes in the United States on a worldwide basis and in numerous state, local and foreign jurisdictions with respect to our income, operations and subsidiaries in those jurisdictions. 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.

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. From time to time, federal and state level legislation in the United States has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies. Such proposed legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies, and (v) an increase in the U.S. federal income tax rate applicable to corporations (such as us). U.S. states in which we operate or own assets may also impose new or increased taxes or fees on oil and natural gas extraction. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting (the “Multilateral Instrument”) has entered into force among the jurisdictions that have ratified it, although the United States has not yet become a signatory to the Multilateral Instrument. Such proposed legislative changes and ratification of the Multilateral Instrument in the jurisdictions in which we operate could result in further changes to our global taxation. Additionally, Mexico has enacted tax reform legislation, and a majority of the provisions became effective on January 1, 2020. These tax reforms provided for new and complex provisions that significantly change how Mexico tax entities and operations and are subject to further legislative change and administrative guidance and interpretation, which may differ from our interpretation. Future tax legislative or regulatory changes in the United States, Mexico or in any other jurisdictions in which we operate now or in the future could also adversely impact our after-tax profitability.

Our Mexican operations are subject to certain offshore regulatory and environmental laws and regulations promulgated by Mexico.

Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by the SENER, the CNH and other Mexican regulatory bodies. The laws and regulations governing activities in the Mexican energy sector have undergone significant reformation over the past decade, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2. Business and Properties — Government Regulation — Regulation in Shallow Waters Off the Coast of Mexico and Part I, Items 1 and 2. Business and Properties — Government Regulation — Hydrocarbon Export Regulation in Mexico for additional disclosure relating to the legal requirements imposed by SENER, CNH or other Mexican regulatory bodies to which we may be subject in the pursuit of our operations.

In addition, our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by the ASEA. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are also relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2. Business and Properties — Environmental and Occupational Safety and Health Regulations — Environmental Regulation in Shallow Waters Off the Coast of Mexico for additional disclosure relating to the legal requirements imposed by ASEA or other Mexican regulatory bodies to which we may be subject in the pursuit of our operations. The permit holders must comply with requirements relating to insurance, facility construction and design, law compliance, and risk analysis scenarios.

Under the Block 7 PSC, we are also jointly and severally liable for the performance of all obligations under the PSC, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractual rescission of the PSC.

Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present, produce in economic quantities.

We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or, if present, produce in economic quantities, and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition.

We are subject to the U.S. Foreign Corrupt Practices Act (the “FCPA”) and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business. We may do business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations or private entities. Thus, we face the risk of unauthorized payments or offers of payments by one of our employees or consultants, given that these parties may not always be subject to our control. Our existing safeguards and any future improvements may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible.

Under the Block 7 PSC with the CNH, we work as a consortium with our partners. Violations of the FCPA, by any consortium partner, may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the CNH has the authority to rescind the PSC if these violations occur.

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 both domestically and abroad. For example, the IRA 2022 contains significant financial incentives for the development of renewable energy, alternative fuels, supporting infrastructure and carbon capture and sequestration and imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge generated from sources in the onshore petroleum and natural gas production categories. Beginning in 2024, the methane emissions charge is set at $900 per ton of methane, and is expected to increase to $1,200 in 2025, and $1,500 in 2026 and each year after. Such additional fees could significantly impact our operating costs. 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.

Numerous other executive actions and legislative and regulatory initiatives have been enacted or may be anticipated, such as cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. Further, regulations or legal actions are likely at the state, regional or international levels of government to monitor and limit existing GHG emissions as well as to restrict or eliminate such future emissions. Additionally, the threat of climate change has resulted in increasing political, litigation and financial risks associated with the production of fossil fuels and GHG emissions. See Part I, Items 1 and 2. Business and Properties — Environmental and Occupational Safety and Health Regulations — Climate Change for additional disclosure relating to risks arising out of the threat of climate change.

The adoption of legislation or regulatory programs to reduce or eliminate future GHG emissions could require us to incur significant operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. 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. Also, political, financial and litigation risks may result in our restricting or canceling production activities or impairing the ability to continue to operate in an economic manner. Further, if any such effects of climate changes were to occur, they could have an adverse effect on our financial condition and results of operations.

Increasing attention to environmental, social and governance matters may impact our business.

Increasing attention to climate change and societal expectations on companies to address climate change and substitute energy sources for fossil fuels may result in increased costs, reduced demand for our products and our services and the products and services of our customers, reduced profits, increased compliance measures, investigations and litigation, and negative impacts on our stock price and access to capital markets.

Moreover, while we endeavor to publish transparent sustainability reports, the voluntary disclosures therein are sometimes based on assumptions and calculations that may or may not be representative of actual or forecasted risks or events, including the costs associated therewith. Such assumptions and calculations are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many environmental, social and governance (“ESG”) matters.

The Board’s SSCR Committee is the primary committee responsible for overseeing and managing our ESG initiatives. 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 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. Moreover, given the evolving nature of GHG emissions accounting methodologies and climate science, it is possible that factors outside of our control could give rise to the need to restate or revise our emissions intensity reduction goals, cause us to miss them altogether, or limit the impact of success of achieving our goals. Additionally, to the extent we meet such targets, they may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net zero goals, or that the offsets we do purchase will successfully achieve the emissions reductions they represent.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. We and other companies in our industry publish sustainability reports that are made available to investors. Such ratings and reports are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital. Additionally, certain institutional lenders may decide not to provide funding to us based on ESG concerns, which could adversely affect our financial condition and access to capital for potential growth projects. To the extent ESG matters negatively impact our reputation, we may also be unable to compete as effectively to recruit or retain employees, which may adversely affect our operations.

Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” (i.e., misleading information or false claims overstating potential ESG benefits). For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG statements, emission reduction claims, approaches to accounting for GHG emissions reductions, or other ESG-related goals or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risk from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further regulatory ESG-related focus and scrutiny.

A change in the jurisdictional characterization of our FERC-jurisdictional pipelines, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such asset, which may cause our revenues to decline and operating expenses to increase or delay or increase the cost of expansion projects.

One of our subsidiaries owns an oil pipeline that extends from South Pass Block 89 in federal waters, offshore Louisiana, to the West Delta Receiving Station in Venice, Louisiana. This subsidiary has previously been granted a waiver of certain portions of the ICA and related regulations by the FERC. However, if the pipeline’s circumstances change, the FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. 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. Such a change in the jurisdictional status of transportation on this pipeline could adversely affect our results of operations. Please also see Part I, Items 1 and 2 Business and Properties — Environmental and Occupational Safety and Health Regulations — Federal Regulation of Sales and Transportation of Crude Oil for more information.

We are upgrading our accounting system to a more recent version and, if this upgraded version proves ineffective or we experience difficulties with the migration, we may be unable to timely or accurately prepare financial reports.

We are in the process of upgrading our accounting systems. Any problems or delays associated with the implementation of our accounting platform or the failure to complete such implementation on a timely basis could adversely affect our ability to report financial information as our company grows, including the filing of our quarterly or annual reports with the SEC on a timely and accurate basis. After converting from prior systems and processes, we may discover data integrity problems or other issues that, if not corrected, could impact our business or financial results.

We have identified material weaknesses in our internal control over financial reporting that could, if not remediated, result in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations.

As more fully disclosed in this Form 10-K/A under Part II, Item 9A. “Controls and Procedures,” our Audit Committee, under the supervision and with the participation of our management, including our interim principal executive officer and principal financial

officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2023. Based on that evaluation, we concluded that our disclosure controls and procedures were not effective as of December 31, 2023 due to material weaknesses identified in our internal control over financial reporting.

A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis.

In September 2024, the Company received a notification from a third party suggesting that the subject employee was engaged in inappropriate procurement practices. In response, the Audit Committee conducted a review of such alleged practices by engaging independent external legal counsel to assist in reviewing the matter and determining the extent of such activities. Such review with external legal counsel did not identify nor implicate other current or former employees and the subject employee was separated from the Company. The Audit Committee also did not identify any related material errors in the Company’s historical financial statements.

However, in the course of its review, the Company identified two material weaknesses. The first material weakness identified was due to our inability to rely on the review control performed by the subject employee with respect to the estimated decommissioning costs incorporated into the asset retirement obligations recognized in our consolidated financial statements. As such, we could not rely on the subject employee’s judgment in the operation of the review control, which is performed upon acquisition of oil and gas assets subject to the retirement obligation and when costs are incurred and reassessed. Although the review of such costs was a task unrelated to the reported conduct subject to our review, we nevertheless determined that the concerns raised regarding the subject employee’s reliability made it inappropriate to have relied on such subject employee’s judgment in the review function. The second material weakness identified was due to inappropriate segregation of duties without designing and maintaining effective monitoring controls over the timely review of expenditures associated with asset retirement obligation spending, capital expenditures and lease operating expenses.

While these material weaknesses did not result in a material misstatement of our consolidated financial statements, these internal control deficiencies were not remediated as of December 31, 2023 and there is a reasonable possibility that it could have resulted in a material misstatement in the Company's annual or interim consolidated financial statements that would not have been detected. Accordingly, we have determined that these internal control deficiencies constituted material weaknesses in our internal control over financial reporting. While management, under the oversight of our Audit Committee, has taken steps to implement our remediation plan as described more fully in Part II, Item 9A. “Controls and Procedures” of this Form 10-K/A, the material weaknesses described above will not be considered remediated until the enhanced controls operate for a sufficient period of time and management has concluded, through testing, that the related controls are effective. Furthermore, we can give no assurance that the measures we take will remediate the material weaknesses.

We can give no assurance that additional material weaknesses will not arise in the future. Any failure to remediate these material weaknesses, or the development of any new material weaknesses in our internal control over financial reporting, could result in material misstatements in our consolidated financial statements and cause us to fail to meet our reporting and financial obligations, which in turn could have a negative impact on our financial condition, results of operations or cash flows, restrict our ability to access the capital markets, require significant resources to correct the material weaknesses or deficiencies, subject us to fines, penalties or judgments, harm our reputation or otherwise cause a decline in both investor confidence and the market price of our stock.

Our debt level and the covenants in our current or future agreements governing our debt, including our Bank Credit Facility, and the indentures governing our New Senior Notes, could negatively impact our financial condition, results of operations and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

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:

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:

See Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Developments — Debt Offering for additional information on the issuance of the New Senior Notes.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas.

We depend on our Bank Credit Facility for a portion of our future capital needs. 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. 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. Our Bank Credit Facility allows us to cure a borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding sufficient to cure the borrowing base deficiency within 30 days after the existence of such deficiency; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency or (iv) any combination of the above. 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. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets are available to pay or refinance such debt. 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. Factors that affect our ability to raise cash through offerings of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing or sale of assets would be successfully completed.

A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets.

We use our cash flows from operating activities and borrowings under our Bank Credit Facility to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. As such, we may not be able to access adequate funding under our Bank Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.

We may also face limitations on our ability to access the debt and equity capital markets and complete asset sales, increased counterparty credit risk on our derivatives contracts and requirements by our contractual counterparties to post collateral guaranteeing performance. Events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. Most recently, on May 1, 2023, First Republic was closed by the California Department of Financial Protection and Innovation (“DFPI”), which appointed the FDIC as receiver. The FDIC sold First Republic’s deposits and most of its assets to JPMorgan Chase Bank, N.A. On March 10, 2023, Silicon Valley Bank (“SVB”) was closed by the DFPI, which appointed the FDIC as receiver. Similarly, on March 12, 2023, Signature Bank and Silvergate Capital Corp. were each swept into receivership. Although a statement by the Department of the Treasury, the Fed and the FDIC indicated that all depositors of SVB would have access to all of their money after only one business day of closure, including funds held in uninsured deposit accounts, borrowers under credit agreements, letters of credit and certain other financial instruments with SVB, Signature Bank or any other financial institution that is placed into receivership by the FDIC may be unable to access undrawn amounts thereunder. Access to funding sources and other credit arrangements could be significantly impaired by factors that affect the financial services industry or economy in general.

In addition, from time to time, we could be required to, or we or our affiliates may seek to, retire or purchase our outstanding debt through cash purchases and/or exchanges for equity or debt, open-market purchases, privately negotiated transactions or other transactions. Such debt repurchase or exchange transactions, if any, will be upon such terms and at such prices as we may determine and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Such transactions may give rise to taxable cancellation of indebtedness income (to the extent the fair market value of the property exchanged, or the amount of cash paid to acquire the outstanding debt, is less than the adjusted issue price of the outstanding debt) and adversely impact our ability to deduct interest expenses in respect of our debt against our taxable income in the future. 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.

We spend a substantial amount of capital for the acquisition, exploration, exploitation, development, and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital is subject to a number of variables, including:

If low oil and natural gas prices, operating difficulties, declines in reserves or other factors, many of which are beyond our control, cause our revenues, cash flows from operating activities, and the borrowing base under our Bank Credit Facility to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity financing will be available, and we cannot be sure that cash flows provided by operations will be sufficient to meet these requirements. For example, the ability of oil and gas companies to access the equity and high yield debt markets has been, and continues to be, significantly limited.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. Accordingly, we are dependent upon distributions from Talos Production Inc. to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. We have no independent means of generating revenue. To the extent Talos Production Inc. has available cash, we will cause Talos Production Inc. to make distributions of cash to us, directly and indirectly through our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. As we have never declared or paid any cash dividends on our common stock, we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our Board of Directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us. To the extent that we need funds and Talos Production Inc. is restricted from making such distributions under applicable law or regulation or under the terms of our financing agreements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt — Limitation on Restricted Payments Including Dividends for additional information.

Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our current and future financial position and results of operations.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs. As a result, we may significantly increase or decrease our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. 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. Gulf of Mexico where the purchasers, as assignees, typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. 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. 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.

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. We expect to grow in the future by expanding the exploitation and development of our existing assets, in addition to growing through targeted acquisitions in the U.S. Gulf of Mexico or in other basins. We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices. In particular, this risk arises in the context of the pending QuarterNorth Acquisition, which is expected to close in the first quarter of 2024.

In addition, integrating acquired businesses and properties involves a number of special risks and unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. These difficulties include, among other things:

Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If our management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

Our current and future acquisitions could expose us to potentially significant liabilities, including P&A liabilities.

We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions, we may only be able to perform limited due diligence.

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental, regulatory and other liabilities, including P&A liabilities. 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.

There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and could potentially expose us to unindemnified liabilities, which could materially adversely affect our production, revenues and results of operations.

Resolution of litigation could materially affect our financial position and results of operations.

Resolution of litigation could materially affect our financial position and results of operations. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we may incur losses that could be material to our financial position or results of operations in future periods.

The corporate opportunity provisions in our Second Amended and Restated Certificate of Incorporation could enable others to benefit from corporate opportunities that might not otherwise be available to us.

Subject to the limitations of applicable law, our Second Amended and Restated Certificate of Incorporation, among other things:

Any of our directors may vote upon any contract or any other transaction between us and any affiliated corporation without regard to the fact that such person is also a director or officer of such affiliated corporation.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others.

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.

Our Second Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our or our stockholders’ behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees, agents and stockholders to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our Second Amended and Restated Certificate of Incorporation or our Second Amended and Restated Bylaws, (iv) any action as to which the DGCL confers jurisdiction to the Court of Chancery of the State of Delaware, or (v) any other action asserting a claim that is governed by the internal affairs doctrine shall be the Court of Chancery of the State of Delaware. Our Second Amended and Restated Certificate of Incorporation also provides that, to the fullest extent permitted by applicable law, the federal district courts of the U.S. are the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act, subject to and contingent upon a final adjudication in the State of Delaware of the enforceability of such exclusive forum provision. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts with respect to suits brought to enforce a duty or liability created by the Securities Act or the rules and regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain claims under the Securities Act.

Notwithstanding the foregoing, the exclusive forum provision does not apply to suits brought to enforce any liability or duty created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring an interest in any shares of our capital stock shall be deemed to have notice of and to have consented to the forum provisions in our Second Amended and Restated Certificate of Incorporation.

These choice-of-forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that he, she or it believes to be favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits. Alternatively, if a court were to find these provisions of our Second Amended and Restated Certificate of Incorporation inapplicable or unenforceable with respect to one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could materially adversely affect our business, financial condition and results of operations and result in a diversion of the time and resources of our management and board of directors.

While the Delaware courts have determined that choice of forum provisions of this type are facially valid, uncertainty exists as to whether a court would enforce such provision, and as such, a stockholder may nevertheless seek to bring a claim in a venue other than those designated in our exclusive forum provision. In such instance, to the extent applicable, we would expect to vigorously assert the validity and enforceability of our exclusive forum provision. This may require additional costs associated with resolving such action in other jurisdictions and there can be no assurance that the provisions will be enforced by a court in those other jurisdictions.

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.

The sale of substantial amounts of shares of our common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

Certain holders of our common stock, including certain former stockholders of EnVen, are entitled to rights with respect to registration of approximately 17.9 million shares of our common stock (representing approximately 11.3% of the outstanding shares of our common stock as of February 21, 2024) under the Securities Act pursuant to certain registration rights agreements. In addition, we intend to enter into a registration rights agreement in connection with the QuarterNorth Acquisition, which will become effective at the closing, which will grant registration rights to approximately 24.8 million shares of our common stock (representing approximately 13.5% of the outstanding shares of our common stock immediately following the closing of the acquisition. If these holders of our common stock, by exercising their registration rights, sell a large number of shares, the market price for our common stock could be adversely affected.

The interests of the Slim Family and its affiliates may differ from the interests of our other stockholders.

As of February 21, 2024, an entity controlled by the Carlos Slim Helu and his family members (collectively, the “Slim Family”) beneficially owned and possessed voting power approximately 21.9% of our common stock.

The Slim Family has significant influence over matters submitted to stockholders for approval, including changes in capital structure, transactions requiring stockholder approval under Delaware law, and corporate governance. The Slim Family may have different interests than other holders of our common stock and may make decisions adverse to your interests.

Among other things, the Slim Family’s concentration of voting power could delay or defer a sale of us that many of our other stockholders support. This concentration of voting power could discourage a potential investor from seeking to acquire our common stock and, as a result, might harm the market price of our common stock.

Risks Related to the QuarterNorth Acquisition and our Integration of QuarterNorth Into our Business

The market price for our common stock following the closing of the QuarterNorth Acquisition may be affected by factors different from those that historically have affected or currently affect our common stock.

Our financial position may differ from our financial position before the completion of the QuarterNorth Acquisition, and the results of operations of the combined company may be affected by some factors that are different from those currently affecting our results of operations. Accordingly, the market price and performance of our common stock is likely to be different from the performance of our common stock in the absence of the QuarterNorth Acquisition. In addition, general fluctuations in stock markets could have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.

Our stockholders, as of immediately prior to the QuarterNorth Acquisition, will have reduced ownership in the combined company after closing of the transaction.

Based on the number of shares of common stock outstanding immediately following the closing of the QuarterNorth Acquisition, our existing stockholders would own approximately 86.5% of the outstanding shares of the combined company and QuarterNorth’s existing members would own approximately 13.5% of the outstanding shares of the combined company. As a result, our current stockholders will have less influence on the policies of the combined company than they currently have following the closing of the QuarterNorth Acquisition.

We may not consummate the QuarterNorth Acquisition on the terms currently contemplated or at all.

We may not consummate the QuarterNorth Acquisition, which is subject to the satisfaction of customary closing conditions. Many of the conditions to completion of the QuarterNorth Acquisition are not within either our or QuarterNorth’s control, and neither we nor QuarterNorth can predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the outside date, it is possible that the QuarterNorth Acquisition may be terminated. Although we have agreed with QuarterNorth to use reasonable best efforts, subject to certain limitations, to promptly complete the QuarterNorth Acquisition, these and other conditions to the completion of the QuarterNorth Acquisition may fail to be satisfied. In addition, satisfying the conditions to and completion of the QuarterNorth Acquisition may take longer, and could cost more, and require additional borrowings, than we currently expect. There can be no assurance that such conditions will be satisfied or that the QuarterNorth Acquisition will be consummated on the terms currently contemplated or at all. If additional borrowings are required to consummate the QuarterNorth Acquisition, our total debt and leverage will be greater than currently anticipated, and our availability under our Bank Credit Facility will be reduced by a corresponding amount. If we fail to complete the QuarterNorth Acquisition, our management will have broad discretion in the use of proceeds from the January Equity Offering (as defined herein), and may use such proceeds in ways in which you do not approve.

Failure to complete the QuarterNorth Acquisition could negatively impact our stock price and have a material adverse effect on our results of operations, cash flows and financial position.

If the QuarterNorth Acquisition is not completed for any reason, including as a result of failure to obtain all requisite regulatory approvals, we may be materially adversely affected and, without realizing any of the benefits of having completed the acquisition, we would be subject to a number of risks, including the following:

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

Future sales or issuances of our common stock could have a negative impact on our common stock price.

If holders of our common stock, by exercising registration rights or otherwise, sell a large number of shares, the market price for our common stock could be adversely affected. It is possible that some QuarterNorth shareholders will decide to sell some or all of the shares of our common stock that they received as consideration in the QuarterNorth Acquisition. Shortly after the closing of the QuarterNorth Acquisition, we are obligated to file a registration statement covering the resale of potentially all of the shares issued to the QuarterNorth shareholders. In addition, in connection with the closing of the QuarterNorth Acquisition, we will enter into a registration rights agreement with certain QuarterNorth shareholders, pursuant to which we will grant such holders certain demand, “piggy-back” registration rights with respect to shares of our common stock received by such holders in the acquisition, subject to a lock-up period of 60 days following the closing.

Following the closing of the QuarterNorth Acquisition, the QuarterNorth shareholders will collectively own 24.8 million shares of our common stock, representing approximately 13.5% of the outstanding shares of our common stock after the closing of that acquisition. We expect that at least a majority of those shares will be subject to the lock-up period.

Any disposition by a significant stockholder of our common stock, including by one of the RRA Holders, or the perception in the market that such dispositions could occur, may cause the price of our common stock to fall. Any such decline could impair the combined company’s ability to raise capital through future sales of our common stock. Further, our common stock may not qualify for investment indices and any such failure may discourage new investors from investing in our common stock.

Our and QuarterNorth’s business relationships may be subject to disruption due to uncertainty associated with the QuarterNorth Acquisition, which could have a material adverse effect on the results of operations, cash flows and financial position of us pending and following the closing of the QuarterNorth Acquisition.

Parties with which we or QuarterNorth do business may experience uncertainty associated with the QuarterNorth Acquisition, including with respect to current or future business relationships with us following the closing of the QuarterNorth Acquisition. Our and QuarterNorth’s business relationship may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than us or QuarterNorth following the QuarterNorth Acquisition. These disruptions could have a material and adverse effect on the results of operations, cash flows and financial position of us, regardless of whether the QuarterNorth Acquisition is completed, as well as a material and adverse effect on our ability to realize the expected benefits of the QuarterNorth Acquisition.

The QuarterNorth Merger Agreement subjects us to restrictions on our business activities prior to the Effective Time.

The QuarterNorth Merger Agreement subjects us to restrictions on our business activities prior to the closing of the QuarterNorth Acquisition (the “Effective Time”). The QuarterNorth Merger Agreement obligates each of us and QuarterNorth to generally conduct our businesses in the ordinary course until the Effective Time and to use commercially reasonable efforts to preserve intact our present business organizations. Additionally, the QuarterNorth Merger Agreement restricts us and QuarterNorth from certain other actions prior to the Effective Time, including, among other things, (i) amending our respective organizational documents, (ii) issuing, selling, pledging, disposing of or encumbering any of our respective securities and (iii) merging, consolidating, combining or amalgamating with any person or acquiring any assets or incurring indebtedness in excess of certain monetary thresholds.

These restrictions could prevent us from pursuing certain business opportunities that arise prior to the Effective Time.

The failure to successfully integrate our business and operations with QuarterNorth in the expected time frame may adversely affect our future results.

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. Specifically, the following issues, among others, must be addressed in integrating the operations in order to realize the anticipated benefits of the QuarterNorth Acquisition:

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.

See the Consolidated Financial Statements and Report of Independent Registered Public Accounting Firm as of December 31, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021, included in Part IV, Item 15. “Exhibits and Financial Statements Schedules“ of this Form 10-K/A.

As of the end of the period covered by this Form 10-K/A, the Company’s management, with the participation of our former chief executive officer and chief financial officer, carried out an evaluation of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon that evaluation, our former chief executive officer and chief financial officer concluded at that time that the Company’s disclosure controls and procedures were designed at a reasonable assurance level and were effective, as of the end of the period covered by the Original Filing, to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our former chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Subsequent to this evaluation, management, with the participation of our interim chief executive officer and chief financial officer, reevaluated the Company’s disclosure controls and procedures as of December 31, 2023. Based on this reevaluation, management concluded that the disclosure controls and procedures were not effective as of December 31, 2023 as a result of the material weaknesses in our internal control over financial reporting described below. Notwithstanding the identified material weaknesses, management concluded that our consolidated financial statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K/A fairly present, in all material respects, our financial condition, results of operations and cash flows as of and for the periods presented in conformity with accounting principles generally accepted in the United States of America (“GAAP”).

Management’s Annual Report on Internal Control over Financial Reporting (As Restated)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Management conducted an assessment of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on the assessment, management concluded that its internal control over financial reporting was effective as of December 31, 2023 to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our consolidated financial statements in accordance with GAAP. Our independent registered public accounting firm, Ernst & Young LLP, also issued an audit report with respect to our internal control over financial reporting, which was included in the Original Filing. Subsequently, management has now concluded that, as of December 31, 2023, our internal control over financial reporting was not effective because of the material weaknesses in our internal control over financial reporting described below.

A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company's annual or interim financial statements will not be prevented or detected on a timely basis.

Notwithstanding the identified material weaknesses above, management has concluded that the consolidated financial statements included in the Original Filing fairly present, in all material respects, the Company’s financial condition, results of operations and cash flows as of the dates, and for the periods presented, in accordance with GAAP. Such consolidated financial statements are included in this Form 10-K/A for purposes of including our independent registered public accounting firm auditor’s opinion, but have not been amended or restated in any way since the Original Filing.

Management, with oversight from the Audit Committee, has developed a remediation plan to address the material weaknesses. The remediation plan includes, among other things:

We believe that these actions, collectively, will remediate the material weaknesses identified. However, we will not be able to conclude that we have completely remediated the material weaknesses until the applicable controls are fully implemented and operated for a sufficient period of time and management has concluded, through formal testing, that the remediated controls are operating effectively. We will continue to monitor the design and effectiveness of these and other processes, procedures, and controls and will make any further changes management deems appropriate.

Control systems, no matter how well conceived and operated, are designed to provide a reasonable, but not an absolute, level of assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Because of this inherent limitations in all controls systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Because of the inherent limitations in any control system, misstatements due to error or fraud may occur and not be detected.

Except for the unremediated material weaknesses noted above, there were no changes in our internal controls over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during quarter ended December 31, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting for such period.

Refer to the Index to Consolidated Financial Statements on page F-1 for a list of all financial statements filed as part of this Annual Report on Form 10-K.

Other than as stated on the Index to Consolidated Financial Statements on page F-1 with respect to Schedule I, financial statement schedules have been omitted because they are either not material, not required, not applicable or the information required to be presented is included in our Consolidated Financial Statements and related notes.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

We have audited the accompanying consolidated balance sheets of Talos Energy Inc. (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and the financial statement schedule listed in Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 28, 2024, except for the effect of the material weaknesses described in the third paragraph of that report, as to which the date is November 12, 2024, expressed an adverse opinion thereon.

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.

February 28, 2024, except for the effect of the material weaknesses described in the second paragraph of the Opinion on the Financial Statements above, as to which the date is November 12, 2024.

We have audited Talos Energy Inc.’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, because of the effect of the material weaknesses described below on the achievement of the objectives of the control criteria, Talos Energy Inc. (the Company) has not maintained effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.

In our report dated February 28, 2024, we expressed an unqualified opinion that the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria. Management has subsequently identified an operating deficiency related to the review of the estimated decommissioning costs incorporated into the asset retirement obligations. Additionally, the Company identified a design deficiency within expenditure processes due to inappropriate segregation of duties. As a result, management has revised its assessment, as presented in the accompanying Management’s Annual Report on Internal Control over Financial Reporting (as revised), to conclude that the Company’s internal control over financial reporting was not effective as of December 31, 2023. Accordingly, our present opinion on the effectiveness of internal control over financial reporting as of December 31, 2023, as expressed herein, is different from that expressed in our previous report.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment. Management has identified a material weakness in controls related to the review performed of the estimated decommissioning costs incorporated into the asset retirement obligations recognized in the consolidated financial statements. Management also identified a material weakness for inappropriate segregation of duties without designing and maintaining effective monitoring controls over the timely review of expenditures associated with asset retirement obligation spending, capital expenditures and lease operating expenses.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and the financial statement schedule listed in Item 15(a) (collectively referred to as the “consolidated financial statements”). The material weaknesses were considered in determining the nature, timing and extent of audit tests applied in our audit of the 2023 consolidated financial statements, and this report does not affect our report dated February 28, 2024, except for the effect of the material weaknesses described in the second paragraph of the Opinion on the Financial Statements of that report, as to which the date is November 12, 2024, which expressed an unqualified opinion thereon.

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

February 28, 2024, except for the effect of the material weaknesses described in the third paragraph above, as to which the date is November 12, 2024.

Note 1 — Organization, Nature of Business and Basis of Presentation

Organization and Nature of Business

Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017. The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on The New York Stock Exchange under the ticker symbol “TALO.”

The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of low carbon solutions opportunities. The Company leverages 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. The Company is also utilizing its expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.

Basis of Presentation and Consolidation

The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majority-owned subsidiaries and any variable interest entity in which the Parent Company is the primary beneficiary are consolidated. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods reflected herein.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

Segments

The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 2 — Summary of Significant Accounting Policies) and indenture governing the senior notes. See additional information in Note 15 — Segment Information.

Recently Issued Accounting Standards

Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting. The update is intended to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses. The update will require public entities to disclose significant segment expenses that are regularly provided to the chief operating decision maker and included within segment profit and loss. The update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 on a retrospective basis. Early adoption is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

Tax Disclosures — In December 2023, the FASB issued an update which expands disclosures in an entity’s income tax rate reconciliation table and regarding cash taxes paid both in the U.S. and foreign jurisdictions. The update is effective for annual periods beginning after December 15, 2024 on a prospective basis. However, retrospective application in all periods presented is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability of material receivables is assessed using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. As of December 31, 2023 and 2022, the Company had allowances of $8.8 million and $10.7 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets.

Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes.

The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.

Prepaid Assets — Prepaid assets primarily represent prepaid subscriptions, insurance, progress payments for well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”). The progress payments made for well equipment relate to long lead time items which the Company has not taken title to as of period end. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis, the Company adjusts the deposit based on actual royalty payments remitted to the ONRR.

Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least annually. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities.

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. Generally, any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years.

Restricted Cash — Any cash that is legally restricted from use is classified as restricted cash. If the purpose of restricted cash relates to acquiring a long-term asset, liquidating a long-term liability, or is otherwise unavailable for a period longer than one year from the balance sheet date, the restricted cash is included in other long-term assets. Otherwise, restricted cash is included in other current assets in the Consolidated Balance Sheets. The Company acquired funds held in escrow to be used for future plugging and abandonment (“P&A”) obligations assumed through the EnVen Acquisition (as defined in Note 3 — Acquisitions and Divestitures). These escrow accounts required deposits of approximately $100.0 million, which was fully funded by EnVen (as defined in Note 3 — Acquisitions and Divestitures) prior to the consummation of the acquisition. This is reflected as “Restricted Cash” within “Other long-term assets” on the Consolidated Balance Sheets.

Equity Method Investments — The Company generally accounts for investments under the equity method of accounting when it exercises significant influence over the entity’s operating and financial policies but does not hold a controlling financial interest in the entity. The voting percentage that is presumed to provide an investor with the required level of influence necessary to apply the equity method of accounting varies depending on the nature of the investee. For investments in common stock, in-substance common stock, a limited liability company or partnership that does not maintain specific ownership accounts for each investor, a voting percentage of 20% or more is generally presumed to demonstrate significant influence. For investments in a limited partnership or unincorporated joint venture and a limited liability company or partnership that maintains a specific ownership account for each investor, a voting percentage of 3-5% or more is generally presumed to demonstrate significant influence. Equity method accounting for interests in limited partnerships is generally appropriate unless the interest is so minor that the investor has virtually no influence (less than 3%).

In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are reflected as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee is reflected in “Equity method investment income (expense)” on the Consolidated Statement of Operations. The gain or loss from the full or partial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee.

The Company assesses equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2023, 2022 and 2021.

Other Well Equipment — Other well equipment primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants.

Notes Receivable, net — The Company holds two notes receivable with an aggregate face value of $66.2 million acquired by the Company as part of the EnVen Acquisition (as defined herein), which consist of commitments from the sellers of oil and natural gas properties related to the costs associated with P&A obligations (the “P&A Notes Receivable”). The P&A Notes Receivable are recorded at a discounted value, being accreted to their principal amounts and presented as such, net of related cumulative estimated credit losses, on the accompanying Consolidated Balance Sheets. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.”

Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,” “Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets.

A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date.

The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes except for our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy, not to record leases with terms of twelve months or less (i.e., short-term) on the Consolidated Balance Sheets. See Note 5 — Leases for additional information.

Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company 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.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 14 — Commitments & Contingencies for additional information.

Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation plan. The Company measures all employee equity-based compensation awards at fair value on the date awards are granted to its employees.

The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity unless the award is modified. Liability classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actual forfeitures, for the restricted stock units (“RSUs”) and performance share units (“PSUs”) in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 10 — Employee Benefits Plans and Share-Based Compensation for additional information.

RSUs — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method.

PSUs with Market Based Conditions — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model for awards with a market condition and recognized over the requisite service period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulfilled, even if the market condition is not achieved.

PSUs with Performance Based Conditions — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method for awards with a performance condition. The Company recognizes compensation cost for awards with performance conditions if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probability assessment. The Company recognizes a cumulative catch-up adjustment for such changes in its probability assessment in subsequent reporting periods, using the grant date fair value of the award whose terms reflect the updated probable performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on a metric associated with the Company’s own operations or activities.

Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties as a reduction of “Lease operating expense” on the Consolidated Statements of Operations.

ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR. The Company records income when a refund is filed and its collection is reasonably assured.

Income Taxes — The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the Consolidated Balance Sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as “Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of RSUs, PSUs and outstanding warrants. See Note 12 — Income (Loss) Per Share for additional information.

Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

•

Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•

Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

•

Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

•

Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

•

Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost).

•

Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Variable Interest Entities — Upon inception of a contractual agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 7 — Equity Method Investments for additional information.

Concentration of Credit Risk

Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk.

Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments.

The Company markets the majority of its oil and natural gas production, and substantially all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary.

The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:


	Year Ended December 31,
	2023			2022			2021
Shell Trading (US) Company		54	%		44	%		45	%
Valero Energy Corporation		21	%		23	%	**
Chevron Products Company	**				11	%		29	%

** Less than 10%

The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the total of the same such amounts shown in the Consolidated Statement of Cash Flows (in thousands):


	Year Ended December 31,
	2023		2022
Cash and cash equivalents	$	33,637	$	44,145
Restricted cash included in Other long-term assets		102,362		—
Total cash, cash equivalent and restricted cash	$	135,999	$	44,145

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 13, 2023 (in thousands):


Current assets	$	243,571
Property and equipment		1,455,347
Other long-term assets:
Restricted cash		100,753
Notes receivable, net		14,844
Other long-term assets		48,899
Current liabilities:
Current portion of long-term debt		(33,234	)
Current portion of asset retirement obligations		(7,079	)
Other current liabilities		(124,347	)
Long-term liabilities:
Long-term debt		(233,836	)
Asset retirement obligations		(251,779	)
Deferred tax liabilities		(150,264	)
Other long-term liabilities		(14,976	)
Allocated purchase price	$	1,047,899

The fair values determined for accounts receivable, accounts payable and other current assets and most current liabilities were equivalent to the carrying value due to their short-term nature. Assumed debt was valued based on observable market prices.

The fair value of proved oil and natural gas properties as of the acquisition date is based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows incorporating market participant assumptions. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments were applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class. These inputs are classified as Level 3 unobservable inputs, including the underlying commodity price assumptions which are based on the five-year NYMEX forward strip prices, escalated for inflation thereafter, and adjusted for price differentials.

The fair value of asset retirement obligations is determined by calculating the present value of estimated future cash flows related to the liabilities. The Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate.

The Company incurred approximately $21.8 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $12.8 million was recognized during the year ended December 31, 2023 and $9.0 million was recognized during the year ended December 31, 2022 and reflected in general and administrative expense on the Consolidated Statements of Operations. Additionally, the Company incurred $25.3 million in severance expense in connection with the EnVen Acquisition for the year ended December 31, 2023. See Note 10 — Employee Benefit Plans and Share-Based Compensation for additional discussion.

The following table presents revenue and net income (loss) attributable to the EnVen Acquisition for the period from February 13, 2023 to December 31, 2023 (in thousands):


	Year Ended December 31, 2023
Revenue	$	423,624
Net income (loss)	$	85,622

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2023 and 2022 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of operations of the Company and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75% Notes (as defined in Note 8 — Debt), (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the year ended December 31, 2022 were adjusted to include $65.1 million of general and administrative expenses, of which $16.3 million were incurred during the year ended December 31, 2022. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude $65.1 million of general and administrative expenses. This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data).


	Year Ended December 31,
	2023		2022
Revenue	$	1,509,929	$	2,355,215
Net income (loss)	$	217,537	$	425,995
Basic net income (loss) per common share	$	1.74	$	3.37
Diluted net income (loss) per common share	$	1.73	$	3.34

Subsequent Event

QuarterNorth Acquisition — On January 13, 2024, the Company executed a merger agreement to acquire QuarterNorth Energy Inc. (“QuarterNorth,” and such acquisition, the “QuarterNorth Acquisition”), a privately-held U.S. Gulf of Mexico exploration and production company. The QuarterNorth Acquisition is expected to close during the first quarter of 2024. Consideration for the QuarterNorth Acquisition primarily consists of (i) approximately $964.9 million in cash, (ii) the amount of net unrestricted cash of QuarterNorth as of December 31, 2023 and (iii) 24.8 million shares of the Company’s common stock.

Divestiture

Mexico Divestiture — On September 27, 2023, the Company closed the sale of a 49.9% equity interest in its subsidiary, Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”) to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo Carso, for $74.9 million in cash consideration with an additional $49.9 million contingent on first oil production from the Zama Field (the “Mexico Divestiture”). The contingent consideration will be recognized when regular commercial production from the Zama Field becomes probable. Talos Mexico, through its wholly owned subsidiary, holds a 17.4% unitized interest in the Zama Field.

As a result of the Mexico Divestiture, Talos Mexico was deconsolidated on September 27, 2023 and is now accounted for as an equity method investment. Total assets derecognized included $112.3 million of unproved properties associated with exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. The fair value of the Company’s retained equity method investment in Talos Mexico was $107.6 million. The determination of fair value was based on the implied fair value of Talos Mexico. The implied fair value of Talos Mexico was based on the transaction price of the Mexico Divestiture, which was an orderly transaction between market participants. A gain of $66.2 million was recognized on the Mexico Divestiture during the year ended December 31, 2023 which is included in “Other operating (income) expense” on the Consolidated Statements of Operations.

During the year ended December 31, 2023, the Company derecognized $112.3 million of unproved properties associated with the exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. See Note 3 — Acquisitions and Divestitures for additional discussion.

During the year ended December 31, 2021, the Company’s evaluation of unproved property located offshore Mexico resulted in a non-cash impairment of $18.1 million presented as “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations. The non-cash impairment was primarily attributable to the Company’s operations in offshore Mexico in Block 31 associated with the Company’s non-consent of the proposed appraisal plan during the fourth quarter of 2021.

The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2023, by the year in which such costs were incurred (in thousands):


			Year Ended December 31,
	Total		2023		2022		2021		2020 and Prior
Acquisition United States	$	249,799	$	229,216	$	—	$	—	$	20,583
Exploration United States		18,516		10,108		1,299		2,295		4,814
Total unproved properties, not subject to amortization	$	268,315	$	239,324	$	1,299	$	2,295	$	25,397

The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. The unproved costs will be excluded from the amortization base until the Company has made a determination as to the existence of proved reserves. The Company currently estimates these costs will be transferred to the amortization base over eight years.

Note 5 — Leases

The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Additionally, the Company has a finance lease related to the use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. The HP-I is utilized in the Company’s oil and natural gas development activities and the ROU asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized.

In November 2022, the Company exercised its option to extend the lease of the HP-I through June 1, 2024. The extension resulted in a remeasurement of the lease liability to $166.3 million and corresponding adjustment to proved property.

The lease costs described below are presented on a gross basis and do not represent the Company’s net proportionate share of such amounts. A portion of these costs have been or may be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands):


	Year Ended December 31,
	2023			2022		2021
Finance lease cost - interest on lease liabilities	$	14,476		$	7,558	$	11,453
Operating lease cost, excluding short-term leases(1)		4,883			2,281		2,706
Short-term lease cost(2)		117,132			55,072		38,472
Variable lease cost(3)		2,888			1,450		1,356
Variable and fixed sublease income		(482	)		—		—
Total lease cost	$	138,897		$	66,361	$	53,987

(1)

Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

(2)

Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets.

(3)

Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

The present value of the fixed lease payments recorded as the Company’s ROU asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands):


	Year Ended December 31,
	2023		2022
Operating leases:
Operating lease assets	$	11,418	$	5,903

Current portion of operating lease liabilities	$	2,666	$	1,943
Operating lease liabilities		18,211		14,855
Total operating lease liabilities	$	20,877	$	16,798

Finance leases:
Proved properties	$	166,261	$	166,261

Other current liabilities	$	17,834	$	16,306
Other long-term liabilities		131,230		149,064
Total finance lease liabilities	$	149,064	$	165,370

The table below presents the lease maturity by year as of December 31, 2023 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the Consolidated Balance Sheets.


	Operating Leases			Finance Leases
2024	$	4,748		$	30,782
2025		4,716			30,782
2026		4,803			30,782
2027		4,708			30,782
2028		4,610			30,782
Thereafter		4,584			43,608
Total lease payments	$	28,169		$	197,518
Imputed interest		(7,292	)		(48,454	)
Total lease liabilities	$	20,877		$	149,064

The table below presents the weighted average remaining lease term and discount rate related to leases:


	Year Ended December 31,
	2023			2022			2021
Weighted average remaining lease term:
Operating leases	5.9 years			6.4 years			7.4 years
Finance leases	6.4 years			7.4 years			1.4 years
Weighted average discount rate:
Operating leases		10.8	%		11.8	%		11.9	%
Finance leases		9.2	%		9.2	%		21.9	%

The table below presents the supplemental cash flow information related to leases (in thousands):


	Year Ended December 31,
	2023			2022		2021
Operating cash outflow from finance leases	$	14,476		$	7,181	$	11,453
Operating cash outflow from operating leases	$	6,318		$	3,722	$	3,864

ROU assets obtained in exchange for new finance lease liabilities	$	—		$	166,261	$	—
ROU assets obtained in exchange for new operating lease liabilities(1)	$	12,971		$	474	$	1,020
Remeasurement of lease liability arising from modification of ROU asset(2)	$	(5,124	)	$	—	$	—

(1)

See EnVen Acquisition in Note 3 — Acquisitions and Divestitures.

(2)

Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effect contemporaneously with the effective date of the modification.

Note 6 — Financial Instruments

As of December 31, 2023 and 2022, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments.

Debt Instruments

The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands):


	December 31, 2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
12.00% Second-Priority Senior Secured Notes – due January 2026	$	601,353	$	655,130	$	590,132		$	674,542
11.75% Senior Secured Second Lien Notes – due April 2026	$	234,221	$	233,410	$	—		$	—
Bank Credit Facility – matures March 2027	$	190,100	$	200,000	$	(4,792	)	$	—

The carrying value of the senior notes are adjusted for discount, premium and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices and, where such prices are not available, other observable (Level 2) inputs are used such as quoted prices for similar liabilities in the active markets.

The carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred financing costs. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

Oil and Natural Gas Derivatives

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. The Company is currently utilizing oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Typical collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.

In connection with the EnVen Acquisition, the Company assumed oil and natural gas collar contracts that combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these contracts, when the NYMEX average closing price is below the floor price, the Company receives the difference between the NYMEX average closing price and the floor price, capped at the difference between the floor price and the short put price.

The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands):


	Year Ended December 31,
	2023			2022			2021
Net cash received (paid) on settled derivative instruments	$	(9,457	)	$	(425,559	)	$	(290,164	)
Unrealized gain (loss)(1)		90,385			153,368			(128,913	)
Price risk management activities income (expense)	$	80,928		$	(272,191	)	$	(419,077	)

(1)

Includes $1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023.

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2023:


Swap Contracts
Production Period	Settlement Index	Volumes		Swap Price
Crude oil:		(Bbls)		(per Bbl)
January 2024 – December 2024	NYMEX WTI CMA		16,859	$	74.30
January 2025 – December 2025	NYMEX WTI CMA		7,734	$	73.80
Natural gas:		(MMBtu)		(per MMBtu)
January 2024 – December 2024	NYMEX Henry Hub		18,716	$	3.41
January 2025 – December 2025	NYMEX Henry Hub		13,712	$	3.92


Two-Way Collar Contracts
Production Period	Settlement Index	Volumes		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
January 2024 – December 2024	NYMEX WTI CMA		1,497	$	70.00	$	79.32
Natural gas:		(MMBtu)		(per MMBtu)		(per MMBtu)
January 2024 – December 2024	NYMEX Henry Hub		10,000	$	4.00	$	6.90

        Three-Way Collar Contracts

        Production Period

        Settlement Index

        Volumes

        Short Put Price

        Floor Price

        Ceiling Price

        Crude oil:

        (Bbls)

        (per Bbl)

        (per Bbl)

        (per Bbl)

January 2024 – March 2024

NYMEX WTI CMA

3,200

57.27

70.00

98.01

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):


	December 31, 2023
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	53,703		$	—	$	53,703
Liabilities:
Oil and natural gas derivatives		—		(8,100	)		—		(8,100	)
Total net asset (liability)	$	—	$	45,603		$	—	$	45,603


	December 31, 2022
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	32,883		$	—	$	32,883
Liabilities:
Oil and natural gas derivatives		—		(76,242	)		—		(76,242	)
Total net asset (liability)	$	—	$	(43,359	)	$	—	$	(43,359	)

Financial Statement Presentation

Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands):


	December 31, 2023				December 31, 2022
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	36,152	$	7,305	$	25,029	$	68,370
Non-current		17,551		795		7,854		7,872
Total gross amounts presented on balance sheet		53,703		8,100		32,883		76,242
Less: Gross amounts not offset on the balance sheet		8,100		8,100		32,883		32,883
Net amounts	$	45,603	$	—	$	—	$	43,359

Credit Risk

The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2023 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and eight of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Had the Company’s counterparties failed to perform under existing commodity derivative contracts the maximum loss at December 31, 2023 would have been $45.6 million.

Note 7 — Equity Method Investments

The following table presents the Company’s investments in unconsolidated affiliates by segment for the periods indicated below. The Company accounts for these investments using the equity method of accounting.


	Ownership Interest at			Year Ended December 31,
	December 31, 2023			2023		2022
Upstream:
Talos Energy Mexico 7, S. de R.L. de C.V		50.1	%	$	107,259	$	—
SP 49 Pipeline LLC		33.3	%		861		374
CCS:
Bayou Bend CCS LLC		25.0	%		28,183		1,371
Harvest Bend CCS LLC		65.0	%		9,746		—
Coastal Bend CCS LLC		50.0	%		—		—
Total Equity Method Investments				$	146,049	$	1,745

Talos Energy Mexico 7, S. de R.L. de C.V.

See Note 3 – Acquisitions and Divestitures for additional information on the deconsolidation of Talos Mexico. There is $66.0 million positive basis difference related to this investment, which will be amortized on a units of production method once regular commercial production from the Zama Field commences.

Bayou Bend CCS LLC

On March 8, 2022, the Company made a $2.3 million cash contribution for a 50% membership interest in Bayou Bend CCS LLC (“Bayou Bend”). Bayou Bend has a CCS site that is in the early stages of development located offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. In May 2022, the Company sold a 25% membership interest to Chevron U.S.A. Inc. (“Chevron”) for upfront cash consideration of $15.0 million. The Company recognized a $13.9 million gain on the partial sale of its investment in Bayou Bend during the year ended December 31, 2022, which is included in “Equity method investment income (expense)” on the Consolidated Statement of Operations. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, which was fully funded by the first quarter of 2023. The Bayou Bend investment was increased with an offsetting gain as the capital carry was funded by Chevron. The Company recognized an $8.6 million and $1.4 million gain during the years ended December 31, 2023 and 2022, respectively, on the funding of the capital carry of its investment in Bayou Bend. This gain is included in “Equity method investment income (expense)” on the Consolidated Statements of Operations.

Effective March 1, 2023, Chevron became the operator of Bayou Bend. During March 2023, Bayou Bend expanded its storage footprint through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship Channel, Beaumont and Port Arthur region.

VIE Disclosures

VIE and Primary Beneficiary Determination — Talos Mexico, Bayou Bend, Harvest Bend CCS LLC (“Harvest Bend”), and Coastal Bend CCS LLC (“Coastal Bend”) were each determined to be a VIE. Neither Talos Mexico, Bayou Bend, Harvest Bend, nor Coastal Bend had sufficient equity at risk to finance their respective activities without additional subordinated financial support. The Company is not the primary beneficiary of these VIE’s due to the governance structure of these entities. The most significant activities of these entities are jointly controlled by the owners. The level of the Company’s economic interest in Harvest Bend is not indicative of the amount of power held.

Financings — All of the Company’s VIE’s have historically been funded through equity contributions from owners.

Maximum Exposure — The Company’s maximum exposure to loss as result of its involvement with VIE’s is the carrying amount of each investment.

Nature of Risks — Talos Mexico holds a working interest in the unitized Zama Field. In March 2023, Petróleos Mexicanos submitted the Zama Unit Development Plan (“UDP”) to Mexico’s governmental agency for approval and the UDP received approved in June 2023. An Integrated Project Team (“IPT”) was formed in March 2023 to pool the talents and competencies of all companies participating in the development of the Zama Field. The IPT reports to the Zama Unit Operating Committee, which includes representatives from each of the participating companies. Final Investment Decision (“FID”) is expected following completion and final review of the front-end engineering and design (“FEED”), project financing and final approvals. Achieving FID is a crucial stage and marks the beginning of the engineering and construction stage, where project contractors proceed with procuring material and beginning the construction. Availability of equipment and unexpected construction hurdles could delay the start of oil and gas production. Even though an IPT exists, teamwork could remain a challenge. There is also a risk that the project will not be completed within the budget and timeline, which ultimately could have an adverse impact on the net present value of the project.

Note 8 — Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):


	Year Ended December 31,
	2023			2022
12.00% Second-Priority Senior Secured Notes – due January 2026	$	638,541		$	638,541
11.75% Senior Secured Second Lien Notes – due April 2026		227,500			—
Bank Credit Facility – matures March 2027		200,000			—
Total debt, before discount, premium and deferred financing cost		1,066,041			638,541
Unamortized discount, premium and deferred financing cost, net		(40,367	)		(53,201	)
Total debt		1,025,674			585,340
Less: Current portion of long-term debt		33,060			—
Long-term debt	$	992,614		$	585,340

12.00% Second-Priority Senior Secured Notes

The 12.00% Second-Priority Senior Secured Notes due 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 the Parent Company (the “Parent Guarantor”), Talos Production Inc. (the “Issuer”), and certain of the Issuer's subsidiaries (the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. 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 Subsidiary Guarantors and will be unconditionally guaranteed on the same basis by certain of the Issuer’s future subsidiaries. The 12.00% Notes are secured on a second-priority 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 mature January 15, 2026 and have interest payable semi-annually each January 15 and July 15.

The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below:


Period	Redemption Price
2023		106.000	%
2024		103.000	%
2025 and thereafter		100.000	%

The indenture governing the 12.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. The 12.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2023.

The Issuer initiated a notes consent solicitation on October 21, 2022, to obtain the requisite holders’ consent to certain amendments to the indenture governing the Issuer’s 12.00% Notes to permit the incurrence of indebtedness in respect of the 11.75% Senior Secured Second Lien Notes due 2026 of EnVen (the “Notes Consent Solicitation”). The Notes Consent Solicitation expired on October 27, 2022, with holders of 95.8% of the aggregate principal amount of the 12.00% Notes outstanding consenting. As a result, the Issuer entered into a second supplemental indenture to the base indenture on October 27, 2022, which became effective upon its execution. The Issuer offered holders of the 12.00% Notes consideration equal to 50 basis points times the principal amount of the 12.00% Notes held by such consenting holder (“Consent Fee”). On February 13, 2023, the Issuer paid the Consent Fee of approximately $3.1 million in the aggregate in connection with the EnVen Acquisition.

During the year ended December 31, 2022, the Company repurchased $11.5 million of the 12.00% Notes. The debt repurchases resulted in a loss on extinguishment of debt for the year ended December 31, 2022 of $1.6 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations.

Subsequent Event — On January 23, 2024, the Company issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.00% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenture. The 12.00% Notes were redeemed on February 7, 2024 for $662.4 million utilizing the net proceeds from the Debt Offering (as defined below).

11.75% Senior Secured Second Lien Notes

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. The 11.75% Notes mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year.

The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below:


Period	Redemption Price
2023		105.875	%
2024		102.938	%
2025 and thereafter		100.000	%

The 11.75% Notes are governed by an indenture by and among Energy Ventures GoM LLC, EnVen Finance Corporation as co-issuers, the guarantors party thereto and Wilmington Trust, National Association as trustee and collateral agent, dated as of April 15, 2021 (“11.75% Notes Indenture”). Talos Production Inc. and certain of its subsidiaries entered into a supplemental indenture to the 11.75% Notes Indenture which, inter alia, provides for the assumption of the indebtedness in respect of the 11.75% Notes by Talos Production Inc., as well as guarantees of such indebtedness by certain subsidiaries of Talos Production Inc., as contemplated by the terms of the 11.75% Notes Indenture.

The 11.75% Notes Indenture contains certain covenants, which are customary with respect to non-investment grade debt securities, including limitations on the Company’s ability to incur and guarantee additional indebtedness, repay, redeem, or repurchase certain debt and capital stock, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on capital stock, enter into certain types of transactions with affiliates, make loans or investments, and make other restricted payments. Additionally, certain covenants restrict Talos Production Inc. subsidiaries’ ability to pay dividends, create liens, and sell certain assets.

Subsequent Event — On January 26, 2024, the Company issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes Indenture. The Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes Indenture and the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes Indenture in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. The Company deposited $247.5 million with the trustee on February 7, 2024 utilizing the net proceeds from the Debt Offering.

11.00% Second-Priority Senior Secured Notes

On January 13, 2021, the Company redeemed $347.3 million aggregate principal amount of the 11.00% Second-Priority Senior Secured Notes due 2022 (the “11.00% Notes”) at 102.75% plus accrued and unpaid interest using the proceeds from the issuance of the 12.00% Notes. The debt redemption resulted in a loss on extinguishment of debt of $13.2 million for the year ended December 31, 2021, which is included in “Other income (expense)” on the Consolidated Statements of Operations.

7.50% Senior Notes

The 7.50% Senior Notes due 2022 matured on May 31, 2022 and were redeemed at an aggregate principal of $6.1 million plus accrued and unpaid interest.

Bank Credit Facility

The Company maintains a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the biannual determination.

The Bank Credit Facility no longer bears interest at the applicable London InterBank Offered Rate plus the applicable margin. Interest under the Bank Credit Facility accrues at the Company’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). The ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5% or (c) the adjusted term SOFR for a one-month interest period plus 1.00%. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and twelve-months) calculated and published by the CME Group Inc. plus 0.10%. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10%. In addition, the Company is obligated to pay a commitment fee on the unutilized portion of the commitments. The pricing grid below shows the applicable margin for Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case based upon the applicable borrowing base utilization percentage:


Borrowing Base Utilization Percentage	Utilization	Term Benchmark Loans and RFR Loans	ABR Loans	Commitment Fee Rate
Level 1	< 25%	2.75%	1.75%	0.38%
Level 2	≥ 25% < 50%	3.00%	2.00%	0.38%
Level 3	≥ 50% < 75%	3.25%	2.25%	0.50%
Level 4	≥ 75% < 90%	3.50%	2.50%	0.50%
Level 5	≥ 90%	3.75%	2.75%	0.50%

The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by, among other things, mortgages covering at least 85.0% of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.

As of December 31, 2023, the Company's borrowing base was $1,075.0 million with total commitments of $965.0 million. Additionally, no more than $250.0 million of the Company’s borrowing base can be used as letters of credit with current commitments at $150.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2023. As of December 31, 2023, the Company had outstanding borrowings at a weighted average interest rate of 8.26%. See Note 14 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2023.

Subsequent Event — On January 13, 2024, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) permits the incurrence of additional indebtedness in order to fund the QuarterNorth Acquisition, with such indebtedness excluded from any reduction of the borrowing base that would otherwise result from such incurrence, and (ii) reaffirms the borrowing base at $1.1 billion effective upon closing of the QuarterNorth Acquisition.

Limitation on Restricted Payments Including Dividends

The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the future that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsidiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsidiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s primary equity method investee as of December 31, 2023 did not have any undistributed earnings.

The Bank Credit Facility contains restrictions on the ability of Talos Production Inc. to transfer funds to the Parent Company in the form of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25% of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00.

In addition, the indenture governing the 12.00% Notes restricts the Company’s consolidated subsidiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indenture. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effect to such transaction on a pro forma basis, the issuer could incur $1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenture.

The indenture governing the 11.75% Notes contains a similar restriction on the Company and its consolidated subsidiaries’ ability to declare or pay dividends, subject to exceptions which include, among other things, (i) subject to no default or event of default having occurred or continuing, dividends in an aggregate amount not to exceed the greater of $25 million and 2.5% of Adjusted Consolidated Net Tangible Assets, (ii) dividends or distributions to any parent company to make payments, in lieu of issuing fractional shares in connection with share dividends, share splits, reverse share splits, mergers, consolidations, amalgamations or other business combinations and in connection with the exercise of warrants, options or other securities convertible into or exchangeable for equity interests of the Company.

At December 31, 2023, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.

Subsequent Event — Debt Offering

On February 7, 2024, the Company closed an upsized offering (the “Debt Offering”) for the sale of $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of second-priority senior secured notes due 2029 and $625.0 million aggregate principal amount of second-priority senior secured notes due 2031 (collectively, the “New Senior Notes”), in a private offering to eligible purchasers that is exempt from registration under the Securities Act. The net proceeds from the Debt Offering (i) are expected to fund a portion of the cash consideration for the pending QuarterNorth Acquisition, (ii) funded the redemption of all of the outstanding 12.00% Notes and all of the outstanding 11.75% Notes discussed above (the “Redemptions”), and (iii) paid premiums, fees and expenses related to the Redemptions and the issuance of the New Senior Notes. The Company intends to use any remaining net proceeds for general corporate purposes, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility.

An aggregate of $340.0 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in the event that the transactions contemplated by the QuarterNorth Merger Agreement are not consummated on or before May 31, 2024 (or up to September 30, 2024 solely in the event the parties require additional time to satisfy certain requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notify the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition.

Note 9 — Asset Retirement Obligations

The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):


	Year Ended December 31,
	2023			2022
Balance, beginning of period	$	541,661		$	434,006
Obligations assumed(1)		258,858			—
Obligations incurred		14,199			1,140
Obligations settled		(86,615	)		(69,596	)
Obligations divested		(19,448	)		(1,572	)
Accretion expense		86,152			55,995
Changes in estimate(2)		102,419			121,688
Balance, end of period	$	897,226		$	541,661
Less: Current portion		77,581			39,888
Long-term portion	$	819,645		$	501,773

(1)

Assumed in connection with the EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.

(2)

Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date.

At December 31, 2023, the Company has (1) restricted cash of $102.4 million inclusive of interest earned to date, held in escrow and (2) the P&A Notes Receivable with an aggregate face value of $66.2 million to settle future asset retirement obligations. These assets are discussed in Note 2 — Summary of Significant Accounting Policies.

Note 10 — Employee Benefits Plans and Share-Based Compensation

EnVen Acquisition Severance

The following table summarizes severance accrual activity in connection with the EnVen Acquisition included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets as of December 31, 2023 (in thousands):


Severance accrual at December 31, 2022	$	—
Accrual additions		25,348
Benefit payments		(19,054	)
Severance accrual at December 31, 2023		6,294
Less: Current portion at December 31, 2023		6,190
Long-term portion at December 31, 2023	$	104

The above table includes involuntary termination benefits that are being provided pursuant to a one-time benefit arrangement that is being spread over the future service period through the termination date. Involuntary termination benefits are also being provided pursuant to contractual termination benefits required by the terms of existing employee agreements. Pursuant to the EnVen Merger Agreement, a rabbi trust was established and funded with $14.5 million at closing to pay a portion of future severance benefits associated with the contractual termination benefits. As of December 31, 2023, the rabbi trust held $3.7 million in assets of which $3.3 million and $0.4 million are included in “Other current assets” and “Other assets,” respectively, on the Consolidated Balance Sheets and both of which are included in the severance accrual at December 31, 2023 listed above. The assets of the rabbi trust are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Severance costs are reflected in “General and administrative expense” on the Consolidated Statement of Operations.

Long Term Incentive Plans

On May 11, 2021, the Company’s stockholders approved the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the Talos Energy Inc. Long Term Incentive Plan (the “2018 LTIP”) (together with the 2021 LTIP, the “LTIP Plans”).

The 2021 LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) RSUs, (vi) awards of vested stock, (vii) dividend equivalents, (viii) other share-based or cash awards and (ix) substitute awards. Employees, non-employee directors and consultants of the Company and its affiliates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up to 8,639,415 shares of the Company’s common stock, subject to the share counting and share recycling provisions of the 2021 LTIP.

Restricted Stock Units – Employees — RSUs granted to employees under the LTIP Plans primarily vest ratably over an approximate three year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of common stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2023 was approximately $19.0 million, which is expected to be recognized over a weighted average period of 1.7 years.

Restricted Stock Units – Non-employee Directors — RSUs granted to non-employee directors under the LTIP Plans vested approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of common stock for each RSU for 60%, and cash for the remaining 40%. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2023 was approximately $0.1 million, which is expected to be recognized over a weighted average period of 0.2 years. Of the unrecognized share-based compensation expense, $0.1 million relates to liability awards and will be subsequently remeasured at each reporting period.

The following table summarizes RSU activity:


	Restricted Stock Units			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2020		1,652,988		$	13.73
Granted		1,102,038		$	13.11
Vested		(669,832	)	$	15.01
Forfeited		(101,995	)	$	12.46
Unvested RSUs at December 31, 2021		1,983,199		$	13.02
Granted		2,297,465		$	13.23
Vested		(967,269	)	$	14.14
Forfeited		(97,891	)	$	14.34
Unvested RSUs at December 31, 2022(1)		3,215,504		$	12.79
Granted		1,154,541		$	16.24
Vested		(1,730,959	)	$	11.97
Forfeited		(332,725	)	$	14.52
Unvested RSUs at December 31, 2023(1)		2,306,361		$	14.89

(1)

As of December 31, 2023 and 2022, 26,975 and 25,257, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

The Company considers its intent and ability to settle awards in cash or shares in determining whether to classify the awards as equity or as a liability. Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The aggregate amount of compensation cost related to these awards is determined by the fair value of the award on the modification date.

Performance Share Units – Employees — PSUs granted to employees under the LTIP Plans represent the contingent right to receive one share of common stock. However, the number of shares of common stock issuable upon vesting ranges from zero to 200% of the target number of PSUs granted. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2023 was approximately $8.7 million, which is expected to be recognized over a weighted average period of 1.7 years.

The following table summarizes PSU activity:


	Performance Share Units			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2020		834,172		$	25.46
Granted		586,995		$	18.96
Vested		(391,308	)	$	39.43
Forfeited		(14,400	)	$	18.48
Unvested PSUs at December 31, 2021		1,015,459		$	16.41
Granted(1)		629,666		$	23.73
Vested(2)		(14,474	)	$	13.05
Forfeited		(16,486	)	$	17.48
Cancelled		(975,564	)	$	16.42
Unvested PSUs at December 31, 2022		638,601		$	23.66
Granted(3)		595,394		$	18.76
Forfeited		(217,346	)	$	21.28
Unvested PSUs at December 31, 2023		1,016,649		$	21.30

(1)

There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

(2)

The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0% based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forfeited they will again be available for new awards under the recycling provisions of the 2021 LTIP.

(3)

There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the relative or absolute TSR PSUs granted and modified at the date indicated:


	2023									2022						2021
	Grant			Grant			Grant			Grant			Grant			Modification			Grant
	December 1			July 1			March 5			September 20			March 5			May 11			March 8
Expected term (in years)		2.1			2.5			2.8			2.3			2.8			2.6			2.8
Expected volatility		61.9	%		66.2	%		73.1	%		74.3	%		82.2	%		80.9	%		78.3	%
Risk-free interest rate		4.4	%		4.6	%		4.5	%		3.9	%		1.6	%		0.3	%		0.3	%
Dividend yield		—	%		—	%		—	%		—	%		—	%		—	%		—	%
Fair value (in thousands)	$	12		$	173		$	6,165		$	621		$	8,668		$	9,715		$	11,129

Modification — During March 2022, the outstanding PSUs held by certain executive officers that were awarded in 2020 and 2021 were cancelled and, in connection with this cancellation, 1,147,352 of RSUs were granted (the “Retention RSUs”). The Retention RSUs will vest ratably each year over two years, generally contingent upon continued employment through each such date. The cancellation of the PSUs along with the concurrent grant of the Retention RSUs are accounted for as a modification. The incremental cost of $9.7 million will be recognized prospectively over the modified requisite service period. Additionally, the remaining unrecognized grant or modification date fair value of the original PSUs will be recognized over the original remaining requisite service period.

Share-based Compensation Costs

Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense” on the Consolidated Statements of Operations, net amounts capitalized to “Proved Properties” on the Consolidated Balance Sheets. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at “Net cash provided by operating activities” on the Consolidated Statements of Cash Flows.

The following table presents the amount of costs expensed and capitalized (in thousands):


	Year Ended December 31,
	2023		2022		2021
Share-based compensation costs	$	25,236	$	28,280	$	20,560
Less: Amounts capitalized to oil and gas properties		12,283		12,327		9,568
Total share-based compensation expense	$	12,953	$	15,953	$	10,992

Note 11 — Income Taxes

Income Tax Expense (Benefit)

The components of income tax expense (benefit) were as follows (in thousands):


	Year Ended December 31,
	2023			2022		2021
Current income tax expense (benefit):
United States	$	76		$	1,375	$	(5	)
Mexico		31			432		(993	)
Total current income tax expense (benefit)	$	107		$	1,807	$	(998	)

Deferred income tax expense (benefit):
United States	$	(60,704	)	$	659	$	(1,067	)
Mexico		—			71		430
Total deferred income tax expense (benefit)	$	(60,704	)	$	730	$	(637	)

Total income tax expense (benefit)	$	(60,597	)	$	2,537	$	(1,635	)

A reconciliation of income tax expense (benefit) computed at the U.S. federal statutory tax rate to the Company’s income tax expense (benefit) is as follows (in thousands, except percentages):


	Year Ended December 31,
	2023			2022			2021
Income tax expense (benefit) at the federal statutory tax rate	$	26,614		$	80,735		$	(38,763	)
State income taxes		1,748			1,591			(674	)
Impact of foreign operations		13,539			15,657			(11,920	)
Effect of change in state rate		—			—			2,008
Prior year taxes		1,184			(2,920	)		486
Change in valuation allowance		(106,815	)		(96,537	)		45,547
Other permanent differences		3,133			4,011			1,681
Total income tax expense (benefit)	$	(60,597	)	$	2,537		$	(1,635	)
Effective tax rate		(47.81	)%		0.66	%		0.89	%

The Company’s effective tax rate for the year ended December 31, 2023 differed from the federal statutory rate of 21.0% primarily due to a non-cash tax benefit of $106.8 million related to the release of the valuation allowance for its deferred tax assets offset with permanent differences and state income tax expense.

The Company’s effective tax rate for the years ended December 31, 2022 and 2021 differed from the federal statutory rate of 21.0% primarily due to recording a full valuation allowance against its federal, state and foreign deferred tax assets.

Deferred Tax Assets and Liabilities

Net deferred tax assets (liabilities) reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of deferred tax assets and liabilities were as follows (in thousands):


	Year Ended December 31,
	2023			2022
Deferred tax assets:
Federal net operating loss	$	147,252		$	159,257
Foreign tax loss carryforward		509			44,462
State net operating loss		24,840			24,787
Tax credits		107			107
Interest expense carryforward		46,414			23,262
Asset retirement obligations		190,248			115,848
Derivatives		—			9,273
Other well equipment		1,317			1,891
Accrued bonus		5,050			5,863
Share-based compensation		5,172			5,296
Operating lease liabilities		4,427			3,669
Finance lease liabilities		31,607			32,559
Other		3,383			7,142
Total deferred tax assets		460,326			433,416
Valuation allowance		(23,697	)		(129,105	)
Total deferred tax assets, net	$	436,629		$	304,311

Deferred tax liabilities:
Oil and gas properties	$	512,918		$	302,602
Operating lease assets		2,421			1,323
Derivatives		9,670			—
Prepaid		3,847			2,530
Total deferred tax liabilities		528,856			306,455
Net deferred tax liability	$	(92,227	)	$	(2,144	)

Net Operating Loss

The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2023 (in thousands):


	Amount		Expiration Year
Federal net operating losses	$	452,393	2035 - 2037
Federal net operating losses	$	248,807	Unlimited
Foreign tax loss carryforward	$	1,696	2025 - 2032
State net operating losses	$	125,958	2025 - 2037
State net operating losses	$	277,930	Unlimited

As of December 31, 2023, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $701.2 million, all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire at the end of 2035.

Valuation Allowance

The Company recorded a valuation allowance of $23.7 million and $129.1 million as of December 31, 2023 and 2022, respectively. Deferred income tax assets and liabilities are recorded related to NOLs and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or NOLs relate.

In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized using available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the Company’s ability to consider other subjective positive evidence.

At December 31, 2022, the Company maintained a valuation allowance related to federal, state and foreign deferred tax assets, as there was insufficient positive evidence to overcome the substantial negative evidence of being in a cumulative loss position. At December 31, 2023, the Company is no longer in a cumulative loss position and reached the conclusion that it is appropriate to release the valuation allowance against its federal deferred tax assets due to the sustained positive operating performance and the availability of expected future taxable income. The Company’s remaining valuation allowance primarily relates to various state operating loss carryforwards.

Uncertain Tax Positions

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. None of the unrecognized benefits would impact the effective tax rate if recognized. While amounts could change during the next 12 months, the Company does not anticipate having a material impact on its financial statements.

Balances in the uncertain tax positions are as follows (in thousands):


	Year Ended December 31,
	2023		2022		2021
Total unrecognized tax benefits, beginning balance	$	835	$	696	$	648
Increases in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		154		100		21
Tax positions taken during the current period		—		39		27
Total unrecognized tax benefits, ending balance	$	989	$	835	$	696

The Company recognizes interest and penalties related to uncertain tax positions as “Interest Expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Years Open to Examination

The 2020 through 2023 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The statute of limitations with respect to the U.S. federal income tax returns of the Company for years ending on or before December 31, 2019 are closed, except to the extent of any NOL carryover balance.

EnVen Acquisition

On February 13, 2023, the Company completed the EnVen Acquisition, which is further discussed in Note 3 —Acquisitions and Divestitures. The Company recognized a net deferred tax liability of $150.3 million in its purchase price allocation as of the acquisition date to reflect differences between tax basis and the fair value of EnVen’s assets acquired and liabilities assumed. The deferred tax balance is based on preliminary calculations and on information available to management at the time such estimates were made.

Note 12 — Income (Loss) Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs, PSUs and outstanding warrants. The warrants expired unexercised on February 28, 2021.

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):


	Year Ended December 31,
	2023		2022		2021
Net income (loss)	$	187,332	$	381,915	$	(182,952	)

Weighted average common shares outstanding — basic		119,894		82,454		81,769
Dilutive effect of securities		858		1,229		—
Weighted average common shares outstanding — diluted		120,752		83,683		81,769

Net income (loss) per common share:
Basic	$	1.56	$	4.63	$	(2.24	)
Diluted	$	1.55	$	4.56	$	(2.24	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		1,353		865		1,709

Note 13 — Related Party Transactions

Apollo Funds and Riverstone Funds

On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”) and members of management pursuant to which the Talos Energy LLC received a private equity capital commitment. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. On July 5, 2023, the Riverstone Funds ceased being a beneficial owner of more than five percent of the Company’s common stock.

Whistler Acquisition Settlement

On August 31, 2018, the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. A settlement agreement related to a dispute regarding the decommissioning obligation of a Deepwater well was executed in September 2021. For the year ended December 31, 2021, the Company recognized a $4.4 million gain resulting from the settlement which is reflected in “Other income (expense)” on the Company’s Consolidated Statements of Operations.

Registration Rights Agreements

2018 Registration Rights Agreement — On May 10, 2018, the Company entered into a registration rights agreement (the “2018 Registration Rights Agreement”) with certain of the Apollo Funds and the Riverstone Funds, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) and certain clients of MacKay Shields LLC (“MacKay Shields”), relating to the registered resale of the Company’s common stock owned by such parties on such date. Subsequently, the 2018 Registration Rights Agreement was amended to add additional affiliates of the Riverstone Funds as parties to the agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to these parties at the closing of an acquisition on February 28, 2020.

The 2018 Registration Rights Agreement provided that registration rights would terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceased to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. Additionally, the 2018 Registration Rights Agreement provided that registration rights would otherwise terminate at such time as there were no registrable securities outstanding. The 2018 Registration Rights Agreement terminated on July 5, 2023 as there were no registrable securities outstanding.

The Company agreed to bear all of the expenses incurred in connection with any offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. The Company incurred fees of nil, nil, and $0.7 million for the fiscal years ended December 31, 2023, 2022 and 2021, respectively.

2022 Registration Rights Agreement — In connection with the Company’s entry into the EnVen Merger Agreement on September 21, 2022 to acquire EnVen, the Company entered into a registration rights agreement (the “2022 Registration Rights Agreement”) with Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”). Pursuant to the 2022 Registration Rights Agreement, the Company grants to Adage and Bain certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock to be received by such entities in the EnVen Acquisition, subject to certain customary thresholds and conditions. Adage and Bain held approximately 2.3% and 12.2%, respectively, of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by each of Adage and Bain.

Additionally, the Company agreed to pay certain expenses of the parties incurred in connection with the exercise of their rights under such agreement and to indemnify them for certain securities law matters in connection with any registration statement filed pursuant thereto. The Company did not incur any fees for the fiscal year ended December 31, 2023.

Amended and Restated Stockholders’ Agreement and Related Agreements

On May 10, 2018, the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement to, among other things, add additional affiliates of the Riverstone Funds (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provided ownership of the Series A Convertible Preferred Stock would, prior to the conversion thereof on March 20, 2020, count towards certain stock ownership requirements on an as converted basis to retain the Riverstone Funds rights to nominate directors to the board of directors.

On March 29, 2022, the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the termination of the Apollo Funds’ rights thereunder and the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). The Amended and Restated Stockholders’ Agreement, among other things, (i) terminated the rights of the Apollo Funds under the Stockholders’ Agreement and (ii) eliminated the requirement that the board of directors consist of ten members.

In connection with the closing of the EnVen Acquisition, the Company and the Riverstone Funds terminated the Amended and Restated Stockholders’ Agreement and Mr. Robert M. Tichio resigned from the Company’s Board of Directors pursuant to a shareholder support agreement dated as of September 21, 2022 requiring the Riverstone Funds to, among other things, approve the EnVen Merger Agreement and the proposed business combination. In connection with the termination of the Amended and Restated Stockholders’ Agreement, the Company and the Riverstone Funds entered into a letter agreement, dated February 13, 2023, pursuant to which the parties thereto agreed to execute and deliver such additional documents and take all such further action as may be reasonably necessary to cause the Amended and Restated Stockholders’ Agreement to be terminated without any further force and effect.

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at V&E. For the years ended December 31, 2023, 2022 and 2021, the Company incurred fees of approximately $3.3 million, $4.8 million, and $3.1 million, respectively, of which $0.8 million, $1.3 million, and $0.2 million were payable at each respective balance sheet date for legal services performed by V&E.

Slim Family

Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficiaries of a Mexican trust which in turn owns all of the outstanding voting securities of Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Office”). Control Empresarial, a sociedad anónima de capital variable organized under the laws of the United Mexican States, is a holding company with portfolio investments in various companies. Control Empresarial and the Slim Family became related parties on November 7, 2023 when they accumulated greater than ten percent of the Company’s outstanding shares of common stock. Control Empresarial held approximately 12.2% of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by Control Empresarial. The Slim Family own a majority stake in Grupo Carso, which indirectly has an ownership interest in Talos Mexico. See Note 3 – Acquisitions and Divestitures for additional information. The Company had no related party receivable from affiliates of the Slim Family as of December 31, 2023.

Subsequent Event — In connection with the January Equity Offering (defined below), Control Empresarial increased their holding to approximately 21.9% of the Company’s outstanding shares of common stock as of the closing of the January Equity Offering based on SEC beneficial ownership reports filed by Control Empresarial. See Note 17 – Subsequent Events for additional information.

In connection with the Debt Offering in February 2024, the Company consummated a firm commitment debt offering consisting of $1,250.0 million in aggregate principal amount of second-priority senior secured notes in a private offering to eligible purchasers that was exempt from registration under the Securities Act. In connection with the Debt Offering, and after expressing a non-binding indication of interest after commencement of the offering, entities and/or persons related to the Slim Family Office purchased an aggregate principal amount of $312.5 million of such notes from the initial purchasers of such offering. In connection with such transaction, the Company expects to pay Inbursa, a banking institution controlled by the Slim Family Office an advisory fee of approximately $2.7 million. See Note 8 – Debt for additional information regarding the Debt Offering.

Equity Method Investments

The Company had a $5.5 million related party receivable from various equity method investments as of December 31, 2023. This is reflected as “Other, net” within “Accounts Receivable” on the Consolidated Balance Sheets. See Note 7 – Equity Method Investments for additional information on the Company’s equity method investments.

In June 2019, David M. 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 or Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. The litigation was assumed as part of the EnVen Acquisition. 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. As Of December 31, 2023, the Company has recorded $14.3 million as “Other current liabilities” on the Consolidated Balance Sheets related to the litigation.

Performance Obligations

Regulations with respect to the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities in the U.S. Gulf of Mexico and certain obligations under the production sharing contracts with Mexico.

As of December 31, 2023, the Company had secured performance bonds from third party sureties totaling $1.4 billion. The cost of securing these bonds is reflected as “Interest expense” on the Consolidated Statements of Operations. Additionally, as of December 31, 2023, the Company had secured letters of credit issued under its Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 8 — Debt for further information on the Bank Credit Facility.

The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2023 (in thousands):


	2024		2025		2026		2027		Thereafter		Total
Vessel Commitments(1)	$	13,216	$	—	$	—	$	—	$	—	$	13,216
Committed purchase orders(2)		3,083		—		—		—		—		3,083
Other commitments(3)		3,991		327		—		—		—		4,318
Total	$	20,290	$	327	$	—	$	—	$	—	$	20,617

(1)

Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

(2)

Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

(3)

Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.

Decommissioning Obligations

The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of Mexico, is in the chain of title with unrelated third parties either directly or by virtue of divestiture of certain oil and natural gas assets previously owned and assigned by our subsidiaries. Certain counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Regulations or federal laws could require the Company to assume such obligations. The Company reflects such costs as “Other operating (income) expense” on the Consolidated Statements of Operations.

The decommissioning obligations included are in the Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands):


	Year Ended December 31,
	2023			2022			2021
Balance, beginning of period	$	54,269		$	24,336		$	—
Additions		266			8,900			21,056
Changes in estimate		11,613			22,658			—
Reimbursements due from third parties		—			—			3,280
Settlements		(50,584	)		(1,625	)		—
Balance, end of period	$	15,564		$	54,269		$	24,336
Less: Current portion		3,280			42,069			3,756
Long-term portion	$	12,284		$	12,200		$	20,580

Note 15 — Segment Information

The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportable segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. A reportable segment is an operating segment that meets materiality thresholds. The 10% test, as prescribed by the segment reporting accounting guidance, are based on the reported measures of revenue, profit, and assets that are used by the CODM to assess performance and allocate resources. The CCS Segment currently does not meet any of the reportable segment quantitative thresholds. The profit or loss metric used to evaluate segment performance is Adjusted EBITDA, which is defined by the Company as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; 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.

Corporate general and administrative expense include certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of operating segment. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment. The remaining expenses are included in the reconciliation of reportable segment Adjusted EBITDA to consolidated pre-tax net income (loss) as an unallocated corporate general and administrative expense. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the table below.

The following table presents selected segment information for the periods indicated (in thousands):


	Upstream		All Other(1)			Total
Revenues from External Customers:
Year Ended December 31, 2023	$	1,457,886	$	—		$	1,457,886
Year Ended December 31, 2022		1,651,980		—			1,651,980
Year Ended December 31, 2021		1,244,540		—			1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method:
Year Ended December 31, 2023	$	120	$	(12,228	)	$	(12,108	)
Year Ended December 31, 2022		101		(1,166	)		(1,065	)
Year Ended December 31, 2021		—		—			—
Adjusted EBITDA:
Year Ended December 31, 2023	$	979,729	$	(22,883	)	$	956,846
Year Ended December 31, 2022	$	859,840	$	(12,786	)		847,054
Year Ended December 31, 2021		615,798		(4,782	)		611,016
Segment Expenditures:
Year Ended December 31, 2023	$	733,669	$	40,961		$	774,630
Year Ended December 31, 2022		452,674		2,778			455,452
Year Ended December 31, 2021		338,822		—			338,822

(1)

The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

Reconciliations

The following table presents the reconciliations of Adjusted EBITDA to the Company’s consolidated totals (in thousands):


	Year Ended December 31,
	2023			2022			2021
Adjusted EBITDA:
Total for reportable segments	$	979,729		$	859,840		$	615,798
All other		(22,883	)		(12,786	)		(4,782	)
Unallocated corporate general and administrative expense		(6,128	)		(5,280	)		(4,542	)
Interest expense		(173,145	)		(125,498	)		(133,138	)
Depreciation, depletion and amortization		(663,534	)		(414,630	)		(395,994	)
Accretion expense		(86,152	)		(55,995	)		(58,129	)
Write-down of oil and natural gas properties		—			—			(18,123	)
Transaction and other (income) expenses(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 extinguishment of debt		—			(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	)
Income (loss) before income taxes	$	126,735		$	384,452		$	(184,587	)

(1)

Transaction expenses includes $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Note 3 — Acquisition and Divestitures and Note 10 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Note 7 — Equity Method Investments. 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 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 Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.

(3)

The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because the Company does not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):


	Year Ended December 31,
	2023			2022			2021
Segment Expenditures:
Total reportable segments	$	733,669		$	452,674		$	338,822
All other		40,961			2,778			—
Change in capital expenditures included in accounts payable and accrued liabilities		(9,199	)		(60,011	)		28,258
Plugging & abandonment		(86,615	)		(69,596	)		(67,988	)
Decommissioning obligations settled		(50,584	)		(1,625	)		—
Investment in CCS intangibles and equity method investees		(40,946	)		(2,778	)		—
Other deferred payments		(1,545	)		—			(7,921	)
Insurance recovery proceeds		2,802			—			—
Non-cash well equipment transfers		(27,731	)		(6	)		1,086
Other		622			1,728			1,074
Exploration, development and other capital expenditures	$	561,434		$	323,164		$	293,331

Note 16 — Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands):


	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Proved properties	$	7,906,295	$	5,964,340	$	5,232,480
Unproved oil and gas properties, not subject to amortization(1)		268,315		154,783		219,055
Total oil and gas properties		8,174,610		6,119,123		5,451,535
Less: Accumulated depletion		4,143,491		3,484,590		3,072,907
Net capitalized costs	$	4,031,119	$	2,634,533	$	2,378,628
Depletion and amortization rate (Per Boe)	$	27.23	$	18.95	$	16.71

Company's Share of Equity Investees:
Unproved oil and gas properties, not subject to amortization	$	56,579	$	—	$	—

(1)

Amount includes $111.4 million and $110.3 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022 and 2021, respectively.

Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations” on the accompanying Consolidated Balance Sheets. See Note 9 — Asset Retirement Obligations for additional information.

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year.


	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Property acquisition costs:
Proved properties	$	951,703	$	—	$	210
Unproved properties, not subject to amortization		249,688		2,221		—
Total property acquisition costs		1,201,391		2,221		210
Exploration costs(1)		161,296		125,889		23,844
Development costs		805,148		541,512		245,058
Total costs incurred	$	2,167,835	$	669,622	$	269,112

Company's Share of Equity Investees:
Exploration costs	$	290	$	—	$	—

(1)

Amount includes nil, $1.2 million and $6.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2023, 2022 and 2021, respectively.

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and subsurface information obtained from the drilling of existing wells. The Company’s Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of Mexico.

At December 31, 2023, 2022 and 2021, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists.

The following table presents the Company’s estimated proved reserves at its net ownership interest:


	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			Oil Equivalent (MBoe)
Consolidated Entities:
Total proved reserves at December 31, 2020		109,307			257,208			10,858			163,033
Revision of previous estimates		13,619			8,979			5,137			20,252
Production		(16,159	)		(32,795	)		(1,875	)		(23,500	)
Extensions and discoveries		997			2,961			315			1,806
Total proved reserves at December 31, 2021		107,764			236,353			14,435			161,591
Revision of previous estimates		(5,625	)		(8,302	)		(2,002	)		(9,010	)
Production		(14,561	)		(32,215	)		(1,793	)		(21,723	)
Sales of reserves		(158	)		(7,625	)		—			(1,429	)
Extensions and discoveries		3,639			31,340			2,288			11,150
Total proved reserves at December 31, 2022		91,059			219,551			12,928			140,579
Revision of previous estimates		(6,308	)		(62,946	)		(1,283	)		(18,082	)
Production		(18,062	)		(26,194	)		(1,767	)		(24,195	)
Purchases of reserves		41,871			36,690			1,116			49,102
Extensions and discoveries		2,255			12,770			979			5,362
Total proved reserves at December 31, 2023		110,815			179,871			11,973			152,766
Total Proved Developed Reserves as of:
December 31, 2021		93,420			186,442			11,792			136,286
December 31, 2022		80,285			161,727			9,315			116,555
December 31, 2023		98,225			141,823			9,957			131,819
Total Proved Undeveloped Reserves as of:
December 31, 2021		14,344			49,911			2,643			25,305
December 31, 2022		10,774			57,824			3,613			24,024
December 31, 2023		12,590			38,048			2,016			20,947

During 2023, proved reserves increased by 12.2 MMBoe primarily due to a purchases of reserves of 49.1 MMBoe in connection with the EnVen Acquisition and 5.4 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Brutus Field in the Green Canyon core area. This increase was partially offset by a decrease of 24.2 MMBoe of production and a decrease of 18.1 MMBoe from revisions of previous estimates. The revisions were primarily due to a 13.5 MMBoe decrease in reserve volumes due to the decrease in SEC Pricing of $17.47 per Bbl of oil and $4.05 per Mcf of natural gas and an additional decrease in the Phoenix Field in the Green Canyon core area due to well performance.

During 2022, proved reserves decreased by 21.0 MMBoe primarily due to a decrease of 21.7 MMBoe of production. Additionally, there was a decrease of 9.0 MMBoe primarily due to timing of development of certain PUD locations to move beyond five years at the Phoenix Field in the Green Canyon core area and sales of reserves of 1.4 MMBoe primarily related to the Brushy Creek Field in the Shelf and Gulf Coast area. The decrease was partially offset by 11.2 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Pompano Field and the Ram Powell Field located in the Mississippi Canyon core area.

During 2021, proved reserves decreased by 1.4 MMBoe primarily due to a decrease of 23.5 MMBoe of production. The decrease was partially offset by revision to previous estimates of 20.3 MMBoe due to increase in commodity prices as well as 1.8 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Crown and Anchor Field located in the Mississippi Canyon core area.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands):


	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Future cash inflows	$	9,425,055		$	10,674,896		$	8,496,005
Future costs:
Production		(3,090,491	)		(1,906,752	)		(1,868,818	)
Development and abandonment		(2,358,368	)		(1,873,453	)		(1,422,507	)
Future net cash flows before income taxes		3,976,196			6,894,691			5,204,680
Future income tax expense		(589,413	)		(1,114,409	)		(676,778	)
Future net cash flows after income taxes		3,386,783			5,780,282			4,527,902
Discount at 10% annual rate		(343,295	)		(1,411,834	)		(1,087,291	)
Standardized measure of discounted future net cash flows	$	3,043,488		$	4,368,448		$	3,440,611

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure:


	Year Ended December 31,
	2023		2022		2021
Oil price per Bbl	$	78.56	$	96.03	$	67.14
Natural gas price per Mcf	$	2.75	$	6.80	$	3.71
NGL price per Bbl	$	18.77	$	33.89	$	26.62

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development and abandonment costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. All estimated costs to settle asset retirement obligations associated with the Company’s proved reserves have been included in their calculation of development and abandonment of the standardized measure of discounted future net cash flows for each period presented. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):


	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Standardized measure, beginning of year	$	4,368,448		$	3,440,611		$	1,904,934
Sales and transfers of oil, net gas and NGLs produced during the period		(1,065,814	)		(1,340,400	)		(957,576	)
Net change in prices and production costs		(2,835,125	)		2,388,442			2,049,980
Changes in estimated future development and abandonment costs		(19,877	)		(84,391	)		(57,876	)
Previously estimated development and abandonment costs incurred		202,503			20,107			69,125
Accretion of discount		518,110			392,600			199,849
Net change in income taxes		357,321			(327,265	)		(391,834	)
Purchases of reserves		2,033,852			—			—
Sales of reserves		—			(5,218	)		—
Extensions and discoveries		90,244			202,239			45,485
Net change due to revision in quantity estimates		(484,423	)		(255,743	)		426,357
Changes in production rates (timing) and other		(121,751	)		(62,534	)		152,167
Standardized measure, end of year	$	3,043,488		$	4,368,448		$	3,440,611

Schedule I. Condensed Financial Information of Registrant

TALOS ENERGY INC. (PARENT ONLY)

BALANCE SHEETS

(In thousands, except share amounts)


	Year Ended December 31,
	2023			2022
ASSETS
Current assets:
Accounts receivable:
Other, net	$	100		$	—
Prepaid assets		221			169
Other current assets		19			36
Total current assets		340			205
Other long-term assets:
Investments in subsidiaries		2,246,908			1,168,053
Total assets	$	2,247,248		$	1,168,258
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	316		$	249
Accrued liabilities		705			728
Other current liabilities		124			62
Total current liabilities		1,145			1,039
Long-term liabilities:
Other long-term liabilities		90,952			1,643
Total liabilities		92,097			2,682
Commitments and contingencies
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively		—			—
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively		1,275			826
Additional paid-in capital		2,549,097			1,699,799
Accumulated deficit		(347,717	)		(535,049	)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively		(47,504	)		—
Total stockholdersʼ equity		2,155,151			1,165,576
Total liabilities and stockholdersʼ equity	$	2,247,248		$	1,168,258

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF OPERATIONS

(In thousands)


	Year Ended December 31,
	2023			2022			2021
Revenues:
Oil	$	—		$	—		$	—
Natural gas		—			—			—
NGL		—			—			—
Total revenues		—			—			—
Operating expenses:
Lease operating expense		—			—			—
Production taxes		—			—			—
Depreciation, depletion and amortization		—			—			—
Accretion expense		—			—			—
General and administrative expense	$	2,708		$	2,145		$	1,322
Other operating (income) expense		—			—			—
Total operating expenses		2,708			2,145			1,322
Operating income (expense)		(2,708	)		(2,145	)		(1,322	)
Interest expense		—			—			(5	)
Price risk management activities income (expense)		—			—			—
Equity method investment income (expense)		—			—			—
Other income (expense)		(1	)		(1	)		(2	)
Equity earnings (loss) from subsidiaries		128,888			385,968			(180,548	)
Net income (loss) before income taxes		126,179			383,822			(181,877	)
Income tax benefit (expense)		61,153			(1,907	)		(1,075	)
Net income (loss)	$	187,332		$	381,915		$	(182,952	)

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,
	2023			2022			2021
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(1,836	)	$	(809	)	$	(876	)
Cash flows from investing activities:
Distributions from subsidiaries		49,340			809			879
Contributions to subsidiaries		—			—			(3	)
Net cash provided by (used in) investing activities		49,340			809			876
Cash flows from financing activities:
Purchase of treasury stock		(47,504	)		—			—
Net cash provided (used in) by financing activities		(47,504	)		—			—

Net increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents:
Balance, beginning of period		—			—			—
Balance, end of period	$	—		$	—		$	—


德拉瓦	82-3532642
（州或其他司法管轄區成立或組織）	（國稅局僱主識別號）
克萊街333號, 3300套房休斯頓, TX	77002
（主要行政辦公室地址）	(Zip代碼）


		頁面
解釋性說明		3
匯總風險因素		4
	第一部分
項目1A.	風險因素	6
	第二部分
項目8.	財務報表和補充數據	31
項目9A.	控制和程式	31
	第四部分
項目15.	展品和財務報表附表	34


Exhibit Number		Description

2.1#		Agreement and Plan of Merger, dated as of September 21, 2022, by and among Talos Energy Inc., Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III LLC, BCC Enven Investments, L.P. and EnVen Energy Corporation (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).

2.2#		Agreement and Plan of Merger, dated as of January 13, 2024, by and among Talos Energy Inc., QuarterNorth Energy Inc., Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024).

3.1		Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

3.2		Second Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

4.1		Indenture, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

4.2		Form of Stock Certificate for Common Stock of Talos Energy Inc. (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).

4.3		First Supplemental Indenture, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).

4.4		Indenture, dated as of February 7, 2024, and by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee, pursuant to which the 2029 Notes were issued. (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

4.5		Indenture, dated as of February 7, 2024, and by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee, pursuant to which the 2031 Notes were issued. (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

4.6		Form of 12.00% Second-Priority Senior Secured Note due 2026 (included as Exhibit A to Exhibit 4.6 hereto) (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

4.7		Form of 9.000% Second-Priority Senior Secured Note due 2029 (included as Exhibit A to Exhibit 4.4 hereto) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).


4.8		Form of 9.375% Second-Priority Senior Secured Note due 2031 (included as Exhibit A in Exhibit 4.5 hereto) (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

4.9		Registration Rights Agreement, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

4.10		Registration Rights Agreement, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).

4.11		Registration Rights Agreement, dated September 21, 2022, by and among Talos Energy Inc. and the Persons listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).

4.12		Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.10 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on March 1, 2023).

4.13		Second Supplemental Indenture, dated as of October 27, 2022, among Talos Production Inc., the Guarantors named therein and Wilmington Trust National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 28, 2022).

4.14		Indenture, dated as of April 15, 2021, by and among Energy Ventures GoM LLC, EnVen Finance Corporation, Talos Production Inc. (as successor in interest to EnVen Energy Corporation), the other guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

4.15		Second Supplemental Indenture, dated as of February 13, 2023, among Talos Production Inc., each of the other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

4.16		Third Supplemental Indenture, dated as of February 13, 2023, among Talos Production Inc., Energy Ventures GoM LLC, EnVen Finance Corporation, each of the other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

10.1		Credit Agreement, dated as of May 10, 2018, by and among Talos Production LLC, as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders named therein (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K12B/A filed with the SEC on July 18, 2018).

10.2		Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First Lien Agent, and Wilmington Trust, National Association, as Second Lien Agent (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.3†		Offer Letter between Talos Energy Inc. and Shannon Young, dated as of April 13, 2019 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on April 24, 2019).

10.4†		Offer Letter between Talos Energy Inc. and Robert D. Abendschein, dated as of December 26, 2019 (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 23, 2020).

10.5†		Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and Timothy S. Duncan (incorporated by reference to Exhibit 10.10 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

10.6†		Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and John A. Parker (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

10.7†		Employment Agreement, dated as of August 30, 2013, by and between Talos Energy Operating Company LLC and William S. Moss III (incorporated by reference to Exhibit 10.14 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).


10.8†		Separation and Release Agreement by and between the Company and Robert D. Abendschein, effective December 26, 2023 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 29, 2023).

10.9†		Talos Energy Inc. Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.10†		Talos Energy Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

10.11		Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality (Contract Area 7), dated as of September 4, 2015, by and among the National Hydrocarbons Commission, Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore México 7, S. de R.L. de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V. (incorporated by reference to Exhibit 10.9 to Talos Energy Inc.’s Amendment No. 4 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on April 4, 2018).

10.12†		Form of Indemnification Agreement (Directors and Officers) (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

10.13†		Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors) (incorporated by reference to Exhibit 10.20 to Talos Energy Inc.’s Form 10-Q filed with the SEC on August 9, 2018).

10.14†		Form of Talos Energy Inc. Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

10.15†		Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.32 to Talos Energy Inc.’s Registration Statement on Form S-4 (File No. 333-227362) filed with the SEC on September 14, 2018)

10.16†		Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

10.17†		Form of Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).

10.18†		Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 3, 2021).

10.19†		Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022).

10.20†		Form of Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022).

10.21†		Form of Performance Share Unit Cancellation and Release Agreement (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022).

10.22†		Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).

10.23†		Form of Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 26, 2020).

10.24†		Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.5 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 9, 2023).


☑	根據1934年《證券交易所法》第13或15（d）條提交的年度報告


☐	根據1934年《證券交易所法》第13或15（d）條提交的過渡報告


每個班級的標題	交易符號	註冊的每個交易所的名稱
普通股	TALO	紐約證券交易所
優先股購買權		紐約證券交易所


大型加速文件夾	☑	加速編報公司	☐
非加速歸檔	☐	小型上市公司	☐
新興成長型公司	☐


10.25		Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement, dated as of July 3, 2019, by and among Talos Energy Inc., as holdings, Talos Production LLC, as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender, and the lenders (including the new lenders) party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on July 10, 2019).

10.26		Joinder, Commitment Increase Agreement, Second Amendment to Credit Agreement, Borrowing Base Redetermination Agreement, and Amendment to Other Credit Documents, dated as of December 10, 2019, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender, and the lenders (including the new lenders) party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

10.27		Third Amendment to Credit Agreement and Borrowing Base Redetermination Agreement, dated as of June 19, 2020, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swing line lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on June 25, 2020).

10.28		Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement, dated as of June 22, 2021, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party thereto, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on June 23, 2021).

10.29		Incremental Agreement, Borrowing Base Redetermination Agreement and Seventh Amendment to Credit Agreement, dated as of December 21, 2021, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto. (incorporated by reference to Exhibit 10.45 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 25, 2022).

10.30		Borrowing Base Redetermination Agreement and Eighth Amendment to Credit Agreement, dated as of May 4, 2022, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party thereto, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender and the lenders party thereto. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on August 05, 2022).

10.31		Incremental Agreement of Increasing Lenders, dated as of May 4, 2022, by and among DNB Capital LLC and Mizuho Bank, Ltd, as increasing lender, Talos Production Inc., as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, swingline lender and issuing bank and Natixis, New York Branch, as issuing bank.(incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on August 05, 2022).

10.32		Incremental Agreement and Ninth Amendment to Credit Agreement, dated as of December 23, 2022, among Talos Energy Inc., Talos Production Inc., each other Credit Party, JPMorgan Chase Bank, N.A., as Administrative Agent, each Issuing Bank, the Swingline Lender and each of the Lenders (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 27, 2022).

10.33		Tenth Amendment to Credit Agreement, dated January 13, 2024, by and among Talos Energy Inc., as Holdings and a Guarantor, Talos Production Inc., as the Borrower, the other Guarantors party thereto, JPMorgan Chase, N.A., as the Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.33 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

10.34#		Form of QuarterNorth Support Agreement, by and among QuarterNorth Energy Inc., Talos Energy Inc. and the other parties thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024).

21.1		List of Subsidiaries of Talos Energy Inc. (incorporated by reference to Exhibit 21.1 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

22.1		List of Subsidiary Guarantors and Issuers of Guaranteed Securities (incorporated by reference to Exhibit 22.1 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

23.1*		Consent of Ernst & Young LLP.


23.2		Consent of Netherland, Sewell & Associates, Inc. (incorporated by reference to Exhibit 23.2 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

24.1		Powers of Attorney (included on signature pages of Part IV of the Original Filing).

31.1*		Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.

97.1		Talos Energy Inc. Executive Compensation Clawback Policy, effective November 15, 2023 (incorporated by reference to Exhibit 97.1 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

99.1		Netherland, Sewell & Associates, Inc. reserve report for Talos Energy Inc. as of December 31, 2023 (incorporated by reference to Exhibit 99.1 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 29, 2024).

101.INS*		Inline XBRL Instance.

101.SCH*		Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents.

104*		Cover Page Interactive Data File (Embedded within the Inline XBRL document and included in Exhibit 101).


*		Filed herewith.

**		Furnished herewith.

†		Identifies management contracts and compensatory plans or arrangements.

#		Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K, but will be furnished supplementally to the SEC upon request.


		TALOS ENERGY INC.

Date:	November 12, 2024	By:	/s/ Sergio L. Maiworm, Jr.
			Sergio L. Maiworm, Jr.
			Chief Financial Officer and Executive Vice President


Signature	Title	Date

/s/ Joseph A. Mills	Interim Chief Executive Officer and President	November 12, 2024
Joseph A. Mills	(Principal Executive Officer, Director)

/s/ Sergio L. Maiworm, Jr.	Chief Financial Officer	November 12, 2024
Sergio L. Maiworm, Jr.	(Principal Financial Officer, Authorized Signatory)

/s/ Gregory Babcock	Chief Accounting Officer	November 12, 2024
Gregory Babcock	(Principal Accounting Officer, Authorized Signatory)

/s/ Paula R. Glover	Director	November 12, 2024
Paula R. Glover

/s/ Neal P. Goldman	Director	November 12, 2024
Neal P. Goldman

/s/ John “Brad” Juneau	Director	November 12, 2024
John “Brad” Juneau

/s/ Donald R. Kendall, Jr.	Director	November 12, 2024
Donald R. Kendall, Jr.

/s/ Richard Sherrill	Director	November 12, 2024
Richard Sherrill

/s/ Charles M. Sledge	Director	November 12, 2024
Charles M. Sledge

/s/ Shandell Szabo	Director	November 12, 2024
Shandell Szabo


Reports of Independent Registered Public Accounting Firm (PCAOB ID 42)	F-2
Consolidated Balance Sheets as of December 31, 2023 and 2022	F-7
Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021	F-8
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2023, 2022 and 2021	F-9
Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021	F-10
Notes to Consolidated Financial Statements	F-11
Note 1 — Organization, Nature of Business and Basis of Presentation	F-11
Note 2 — Summary of Significant Accounting Policies	F-11
Note 3 — Acquisitions and Divestitures	F-17
Note 4 — Property, Plant and Equipment	F-19
Note 5 — Leases	F-20
Note 6 — Financial Instruments	F-22
Note 7 — Equity Method Investments	F-24
Note 8 — Debt	F-25
Note 9 — Asset Retirement Obligations	F-29
Note 10 — Employee Benefit Plans and Share-Based Compensation	F-29
Note 11 — Income Taxes	F-32
Note 12 — Income (Loss) Per Share	F-34
Note 13 — Related Party Transactions	F-35
Note 14 — Commitments and Contingencies	F-36
Note 15 — Segment Information	F-38
Note 16 — Supplemental Oil and Gas Disclosures (Unaudited)	F-40
Note 17 — Subsequent Events	F-43
Schedule to Consolidated Financial Statements	F-44
Schedule I — Condensed Financial Information of Registrant	F-44


How We Addressed the Matter in Our Audit		We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls that address the risks of material misstatement relating to the DD&A expense calculation, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineers used to audit the proved oil and gas reserve estimates. On a sample basis, we tested the completeness and accuracy of the financial data used in the estimation of proved oil and gas reserves by agreeing significant inputs to source documentation, where available, and assessing the inputs for reasonableness based on review of corroborative evidence and consideration of any contrary evidence. Additionally, we performed analytic and lookback procedures on select inputs into the oil and gas reserve estimate. Finally, we tested that the DD&A expense calculations are based on the appropriate proved oil and gas reserve balances from the Company’s reserve report.

		Evaluation of the fair value measurement of oil and gas properties acquired in the EnVen Energy Corporation business combination
Description of the Matter		As described in Note 3 to the consolidated financial statements, the Company executed a merger agreement to acquire EnVen Energy Corporation for net consideration of approximately $1.0 billion. The transaction was accounted for as a business combination. The Company applied a discounted cash flow method to estimate the fair value of the proved and unproved oil and gas properties acquired. Significant judgment is required by the Company’s internal reservoir engineers in evaluating geological and engineering data when estimating oil and gas reserves. Significant inputs to the valuation of proved and unproved oil and gas properties include estimates of future oil and gas price assumption and production profiles of reserve estimates, reserve category risk adjustment factors and discount rate using a market-based weighted average cost of capital. Auditing the Company’s determination of the fair value of the proved and unproved oil and gas properties acquired was complex due to the significant estimation required by management of reserves associated with the acquired assets and the sensitivity of the significant assumptions used in determining the fair value. In evaluating the reasonableness of management’s estimates and assumptions used, the audit testing procedures performed required a high degree of auditor judgment and additional effort, including involving internal specialists.
How We Addressed the Matter in Our Audit		We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s internal controls over its process to estimate the fair value of the acquired proved and unproved oil and gas properties, including management’s review of the significant assumptions used as inputs to the fair value calculations. To test the estimated fair value of the acquired proved and unproved oil and gas properties, our audit procedures included, among others, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data supporting the significant assumptions. For example, we compared and assessed certain significant assumptions to current industry or third-party data for reasonableness. We also performed sensitivity analyses of significant assumptions, to evaluate the extent of their impact to the fair value calculation. In addition, we involved our valuation specialists to assist with certain significant assumptions included in the fair value estimate. Furthermore, we evaluated the professional qualifications and objectivity of the third-party valuation specialist engaged by the Company to prepare the fair value of the acquired proved and unproved oil and gas properties.

		Asset Retirement Obligations
Description of the Matter		As described in Note 2 and 9 of the consolidated financial statements, the Company records a liability for the Asset Retirement Obligation at fair value in the period in which it is incurred. The retirement obligations are periodically adjusted to reflect changes in the expected cash flows resulting from revisions to the estimates of either the timing or amount of the retirement costs. Due to the complexity involved in estimating the expected cash outflows, management used a specialist to estimate the expected cash outflows for the Company’s asset retirement obligation as of December 31, 2023.


		Auditing management’s accounting for retirement obligations was especially challenging, as significant judgment is required by the Company in determining the obligation. The significant judgment was primarily related to the inherent estimation uncertainty relating to the expected cash outflows extent of future asset retirement activities and the ultimate productive life of the properties.
How We Addressed the Matter in Our Audit		To test the asset retirement obligation, among other procedures, we evaluated the methodology, tested the significant assumptions described above and tested the completeness and accuracy of the underlying data used by the Company in estimating the expected cashflows. To assess the estimates of asset retirement activities and cash flows, we evaluated significant changes from the prior estimate, verified consistency between the timing of asset retirement activities and projected productive life of the properties, verified cost rates against third-party information or internal cost records and recalculated management’s estimate. We involved our asset retirement specialists to assist in our evaluation of the expected cash outflows for asset retirement obligation.


	Common Stock				Additional Paid-In			Accumulated			Treasury Stock					Total Stockholdersʼ
	Shares Issued		Par Value		Capital			Deficit			Shares		Amount			Equity
Balance at December 31, 2020		81,279,989	$	813	$	1,659,800		$	(734,012	)		—	$	—		$	926,601
Equity-based compensation		—		—		20,165			—			—		—			20,165
Equity-based compensation tax withholdings		—		—		(3,161	)		—			—		—			(3,161	)
Equity-based compensation stock issuances		601,488		6		(6	)		—			—		—			—
Net income (loss)		—		—		—			(182,952	)		—		—			(182,952	)
Balance at December 31, 2021		81,881,477		819		1,676,798			(916,964	)		—		—			760,653
Equity-based compensation		—		—		27,611			—			—		—			27,611
Equity-based compensation tax withholdings		—		—		(4,603	)		—			—		—			(4,603	)
Equity-based compensation stock issuances		688,851		7		(7	)		—			—		—			—
Net income (loss)		—		—		—			381,915			—		—			381,915
Balance at December 31, 2022		82,570,328		826		1,699,799			(535,049	)		—		—			1,165,576
Equity-based compensation		—		—		25,008			—			—		—			25,008
Equity-based compensation tax withholdings		—		—		(7,459	)		—			—		—			(7,459	)
Equity-based compensation stock issuances		1,110,143		11		(11	)		—			—		—			—
Issuance of common stock for acquisition (Note 3)		43,799,890		438		831,760			—			—		—			832,198
Purchase of treasury stock		—		—		—			—			3,400,000		(47,504	)		(47,504	)
Net income (loss)		—		—		—			187,332			—		—			187,332
Balance at December 31, 2023		127,480,361	$	1,275	$	2,549,097		$	(347,717	)		3,400,000	$	(47,504	)	$	2,155,151


Talos common stock		43,799,890
Talos common stock price per share(1)	$	19.00
Common stock value	$	832,198

Cash consideration	$	207,313
Settlement of preexisting relationship	$	8,388

Total purchase price	$	1,047,899