Talos Energy Inc.: Form 10-Q for the period ended Mar 31, 2025

Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “Talos” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with, our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2024 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2024 Annual Report.

Our Business

We are a technically driven, innovative, independent energy company focused on maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact.

We have historically focused our operations in the U.S. Gulf of America because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate an inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and collaborative arrangement opportunities, among others.

From January 1, 2024 through March 18, 2024, we had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). Both segments were reportable based on the Company’s measure of segment profit or loss for the year ended December 31, 2024. With the sale of our CCS business during 2024, the Company's Upstream Segment is currently the only reportable segment being managed on a consolidated basis.

Significant Developments

The following significant developments have occurred since the filing of our 2024 Annual Report.

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

Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an incremental 8.3% working interest in the Monument oil discovery in the U.S. Gulf of America located on certain Walker Ridge lease blocks. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information.

Factors Affecting the Comparability of our Financial Condition and Results of Operations

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

QuarterNorth Acquisition — On March 4, 2024, we acquired QuarterNorth Energy Inc. (“QuarterNorth”), a private operator in the Deepwater U.S. Gulf of America (the “QuarterNorth Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information.

Known Trends and Uncertainties

We are navigating through various evolving external factors that create uncertainty and volatility in the operating environment, including, but not limited to, volatility in energy prices and inflation due to geopolitical dynamics, increased tariffs and their impact on costs of goods and services, legal challenges related to the industry, and planned and unplanned downtime. These factors, and any changes to these factors, among others, could have a material adverse impact on our future revenues and overall profitability. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2024 Annual Report for further discussion of Known Trends and Uncertainties, and, Part II, Item 1A “Risk Factors” of this Quarterly Report and Part II, Item 1A. “Risk Factors” in our 2024 Annual Report for additional information regarding our Risk Factors. There have been no material changes to the following topical trends and uncertainties discussed in our 2024 Annual Report:

• Deepwater Operations
• Oil Spill Response Plan
• Hurricanes, Tropical Storms, Winter Storms and Loop Currents

The following provides an update to known trends and uncertainties discussed in our 2024 Annual Report.

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.

During the period January 1, 2025 through March 31, 2025, the daily spot prices for NYMEX WTI crude oil ranged from a high of $80.73 per Bbl to a low of $66.31 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.86 per MMBtu to a low of $2.93 per MMBtu. The price the Company realizes on natural gas sales is based on the MMBtu content of such natural gas. We convert MMBtu sales volumes to Mcf volumes for reporting purposes using MMBtu per Mcf factors per third party natural gas processing plant statements. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices we realize for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments” for additional information regarding our commodity derivative positions as of March 31, 2025.

Recent developments in U.S. trade policy and oil production have led to a significant drop in crude oil prices during April. On April 2, 2025, President Trump signed an Executive Order announcing 10% tariffs on imports from all countries, with higher tariffs initially imposed on some countries. On April 3, 2025, OPEC Plus announced that some countries will start production increases in May 2025 that were originally set for July 2025. Following these announcements, crude oil prices fell sharply. On April 10, 2025, the U.S. Energy Information Administration (“EIA”) published its short-term energy outlook, with expectations that prices for crude oil and other commodities will continue to experience significant volatility as market participants assess the effects of trade policies. The EIA expects global oil inventories will increase starting in the middle of 2025 as OPEC Plus members unwind production cuts, production grows in non-OPEC countries, and oil demand growth slows. The effect that new or additional tariffs will have on global economic activity and associated oil demand is still highly uncertain and could weigh heavily on crude oil prices going forward. The implementation of energy-sector sanctions on Russia and Iran, as well as the wind down of Chevron’s Venezuela oil exports, have increased crude oil price volatility in the short term while markets and trade patterns adjust. The EIA expects the NYMEX WTI spot prices to average $63.88 per barrel in 2025 and $57.48 per barrel in 2026 and Henry Hub price to average around $4.27 per MMBtu in 2025 and $4.60 per MMBtu in 2026.

Inflation and Macroeconomic Pressures — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase. However, during periods of commodity price declines, corresponding reductions in oilfield costs typically do not adjust downward as quickly as oil prices decline.

Inflation may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Inflation may also result in higher interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business.

In March 2025, the U.S. Federal Reserve (the “Fed”) left its benchmark interest rate unchanged at a range of 4.25%-4.50% although the Fed indicated it still anticipates reducing borrowing costs by half a percentage point by the end of 2025 in the context of slowing economic growth and, eventually, a downturn in inflation. Future changes to the benchmark interest rate remain uncertain.

***Impact of Prolonged Increases in Tariffs —***We continue to monitor the rapid changes in global trade policies, including tariff increases, and the impact on our business while evaluating actions to mitigate the impact on our business, results of operations, and financial condition. Any prolonged increases in global tariffs could have a material impact on our financial condition and results of operations in fiscal year 2025 and beyond. The recent tariffs may increase inflation in the near term, lead to slower growth for the U.S. economy and increase the probability of a U.S. recession.

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three months ended March 31, 2025 and 2024, we did not recognize an impairment based on the ceiling test computations. At March 31, 2025 our ceiling test computation was based on SEC pricing of $74.52 per Bbl of oil, $2.78 per Mcf of natural gas and $21.19 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning April 1, 2024 and ending March 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $67.01 per Bbl of oil, $2.53 per Mcf of natural gas and $19.16 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $610.0 million assuming all other factors remained constant.

There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2024 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.

Planned Downtime — We are vulnerable to downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the Helix Producer I (“HP-I”) that is operated by Helix Energy Solutions Group, Inc (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field. The next dry-dock is scheduled for the first half of 2027 with a projected shut-in period of approximately 45 days.

Update on Financial Assurance Rule — Effective June 29, 2024, BOEM adopted a final rule which significantly increases the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the Outer Continental Shelf (“OCS”). The final rule adopted a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demands. The final rule was challenged in the U.S. District Court for the Western District of Louisiana (the “District Court”) by multiple oil and gas industry groups and the States of Mississippi, Louisiana and Texas and the District Court granted a stay of the litigation while the agency pursues efforts to suspend, revise, or rescind the final rule. The District Court’s order temporarily limits BOEM’s full implementation of the final rule by limiting BOEM’s ability to seek supplemental financial assurance to cases of sole liability properties and certain non-sole liability properties that are held by owners who are not financially strong, as described in the final rule, and that have no co-owners or predecessors who are financially strong.

On May 2, 2025, the Department of the Interior (“DOI”) announced its intent to revise and develop a new rule that is consistent with the Trump Administration’s 2020 proposed rule on financial assurance. The specific substance and timing of a revised rule cannot be predicted at this time. However, we anticipate that the new revised rule will revert to BOEM’s decades-long policy of considering the financial strength of both co-owners and predecessors in title when determining whether supplemental financial assurance is required and reduce the credit rating required under the current final rule for financial assurance waivers. In light of these expectations, we anticipate the amount we would be required to bond under the revised rule would be significantly less than under the final rule.

Regardless of the status of the final rule or a new revised rule, BOEM stated it will continue to require operators on the OCS to provide financial assurance in instances where BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

Financial Assurance Market Outlook — As a result of a number of surety companies leaving the offshore surety market due in part to adverse developments in restructurings and bankruptcies of companies operating in the OCS, there continues to be significant uncertainty in the current market availability of surety bonds for projects and companies operating in the OCS. As such, we may not be able to obtain new surety bonds on commercially reasonable terms or maintain existing bonding without posting collateral. Moreover, under our surety agreements, surety companies have the right to demand collateral. If we are required to provide collateral in the form of cash or letters of credit under our Bank Credit Facility, our liquidity position could be significantly impacted. We cannot predict how much collateral, if any, we may be required to provide.

Recent Challenges to Federal Offshore Leasing Program — Gulf of America federal lease sales are conducted pursuant to Five-Year Leasing Programs under the U.S. Outer Continental Shelf Lands Act, as amended (“OCSLA”). U.S. federal offshore oil and gas lease sales have been, and may continue to be, subject to numerous challenges, delays, and moratoriums which may curtail our ability to seek additional new federal leases and may delay or prevent us from bidding on and obtaining new federal offshore leases or developing existing leases. In January 2023, BOEM released its Supplemental Environmental Impact Statement (“SEIS”) related to Lease Sales 259 and 261. In March 2023, BOEM held and announced the results of Lease Sale 259, in which we and QuarterNorth, which we acquired in 2024, were awarded leases on a total of eight blocks. In December 2023, BOEM held and announced the results of Lease Sale 261, in which we and QuarterNorth were awarded leases on a total of seventeen blocks.

Six environmental organizations filed a lawsuit in March 2023 in the U.S. District Court for the District of Columbia seeking to cancel Lease Sale 259 on the basis that BOEM violated its statutory obligation to adequately evaluate the lease sale’s environmental impacts. Plaintiffs argued that the SEIS was deficient in several respects. In March 2025, the court agreed with plaintiffs that BOEM’s SEIS was deficient with respect to its evaluation of greenhouse gas emissions and harms to Rice’s whales but disagreed with plaintiffs regarding other alleged deficiencies. The court requested additional briefing from the parties regarding appropriate remedy. The current ruling leaves open the status of the leases awarded under Lease Sale 259 and we cannot predict the ultimate outcome of this lawsuit. It is possible that, pending the outcome of this litigation, the validity of leases awarded under Lease Sale 259 could be challenged and our ability to develop these leases could be significantly delayed until such legal challenges are resolved. Additionally, an adverse outcome in this lawsuit could potentially result in subsequent challenges to our lease awards under Lease Sale 261. Any actions to restrict, delay or prohibit the oil and natural gas exploration, development and production activities of existing oil and gas leases on the OCS could adversely impact the offshore oil and gas industry and have a material adverse effect on our business, financial condition or results of operations.

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

On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s memoranda and the U.S. Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts and the future of both actions remains undecided. On April 18, 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America, the first of which is expected to be held by the end of 2025. We cannot determine when the 11th National OCS Program will be initiated, or how many lease sales will be scheduled.

Executive, judicial and/or administrative action resulting in the withdrawal of OCS areas from consideration for new leasing activities or delays in scheduling OCS lease sales, particularly if such actions affect the Western and Central Planning Areas of the Gulf of America in which we currently or seek to operate, could have a material adverse effect on our ability to obtain new OCS leases and develop new assets, as well as negatively impact our financial condition and results of operations.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our operations, including:

• production volumes;
• realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;
• lease operating expenses;
• capital expenditures; and
• Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.

Results of Operations

Revenue

The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices. Revenues are presented in thousands, except per unit data.

The information below provides an analysis of the change in our oil, natural gas and NGL revenues due to changes in sales prices and production volumes (in thousands):

Three Months Ended March 31, 2025 and 2024 Volumetric Analysis — Production volumes increased by 21.3 MBoepd to 100.9 MBoepd. The increase was primarily due to 22.8 MBoepd of production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 6.8 MBoepd of production from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. Additionally, there was 2.0 MBoepd in deferred production resulting from third party infrastructure downtime primarily from our Lobster Field in the corresponding period in 2024. These increases were partially offset by a decrease of approximately 8.3 MBoepd due to well performance and natural production declines.

Operating Expenses

Lease Operating Expense

The following table highlights lease operating expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

Three Months Ended March 31, 2025 and 2024 — Lease operating expense for the three months ended March 31, 2025 decreased by approximately $7.4 million, or 5%. This was primarily related to a $30.8 million decrease in workover expenses at the Phoenix Field and Garden Banks 506 Field compared to the same period in 2024. This was partially offset by a $16.9 million increase in direct lease operating expenses due to the QuarterNorth Acquisition that closed in late first quarter of 2024. Additionally, there was a $4.6 million decrease in production handling fees related to reimbursements for costs from certain third parties related to our historical operations.

Depreciation, Depletion and Amortization

The following table highlights depreciation, depletion and amortization items. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

Three Months Ended March 31, 2025 and 2024 — Depreciation, depletion and amortization expense for the three months ended March 31, 2025 increased by approximately $65.1 million, or 30%. This increase was primarily driven by the increased production volumes of 21.3 MBoepd discussed above and to a lesser extent an increase of $1.14 per Boe, or 4% in the depletion rate on our proved oil and natural gas properties. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for further discussion.

General and Administrative Expense

The following table highlights general and administrative expense items in total and on a cost per Boe production basis for the Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

Three Months Ended March 31, 2025 and 2024 — General and administrative expense for the three months ended March 31, 2025 decreased by approximately $35.2 million, or 50%. This decrease was primarily driven by Upstream Segment transaction costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $30.7 million or $3.38 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.8 million due to the divestiture of our CCS business. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for further discussion.

Miscellaneous

The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

Three Months Ended March 31, 2025 and 2024 —

Accretion Expense — During the three months ended March 31, 2025, we recorded $30.9 million of accretion expense compared to $26.9 million during the three months ended March 31, 2024. The change is primarily the result of a $3.1 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition in early March 2024. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”

Other Operating (Income) Expense — During the three months ended March 31, 2024, we recognized a gain of $86.9 million due to the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”

Interest Expense — During the three months ended March 31, 2025, we recorded $40.9 million of interest expense compared to $50.8 million during the three months ended March 31, 2024. The change is primarily due to a $5.1 million decrease in interest expense related to the Bank Credit Facility as a result of lower borrowings compared to the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information. Additionally, there was a decrease of $4.9 million of fees associated with an unutilized bridge loan during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information.

Price Risk Management Activities — The expense of $15.9 million for the three months ended March 31, 2025 consists of $21.0 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $5.2 million in cash settlement gains. The expense of $87.1 million for the three months ended March 31, 2024 consists of $83.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $3.5 million in cash settlement losses.

These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each reporting period. As a result of the derivative contracts we have on our anticipated production volumes through December 2026, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments.”

Equity Method Investment (Income) Expense — During the three months ended March 31, 2024, we recorded equity losses of $8.1 million primarily related to our CCS Segment.

Other (Income) Expense — During the three months ended March 31, 2025, we had $3.9 million of other income compared to $55.9 million in other expense for the three months ended March 31, 2024. The change is primarily a result of a $60.3 million loss on extinguishment of debt from the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) during the three months ended March 31, 2024.

Income Tax (Benefit) Expense — During the three months ended March 31, 2025, we recorded $0.1 million of income tax benefit compared to $21.6 million of income tax benefit during the three months ended March 31, 2024. The income tax benefit recorded during the three months ended March 31, 2025 is primarily due to current year activity offset by the impact from permanent differences. See additional information in Part I, Item 1. “Financial Statements — Note 10 — Income Taxes.”

Supplemental Non-GAAP Measure

EBITDA and Adjusted EBITDA

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

We define these as the following:

• EBITDA — Net income (loss) plus interest expense, income tax benefit (expense), depreciation, depletion and amortization, and accretion expense.
• Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

(1) For the three months ended March 31, 2024, transaction expenses included $28.1 million in costs related to the QuarterNorth Acquisition, inclusive of $14.2 million in severance expense and $9.8 million in costs related to the TLCS Divestiture, inclusive of $3.7 million in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, the amount included a gain of $86.9 million related to the TLCS Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”

(2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 13 — 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 we do 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.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility (as defined herein). Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases and for general corporate purposes. The cost of borrowing under our Bank Credit Facility is influenced by changes in the federal funds rate. As interest rates increase, it becomes more expensive to borrow money while interest rate cuts make it less expensive to borrow money.

Our Bank Credit Facility currently has a borrowing base of $925.0 million but is subject to an $800.0 million availability cap. As of March 31, 2025, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $960.2 million or $1,085.2 million inclusive of the $125.0 million availability cap requiring certain lender approval. Letters of credit that are outstanding reduce the available revolving credit commitments. If oil prices remain at current levels or we are unable to replace proved reserves either through acquisitions or new drilling activity, our borrowing base will likely be reduced at our next redetermination which is expected in the second quarter of 2025 and our available liquidity may be negatively impacted unless offset by cash generated from our operating activities.

We fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the three months ended March 31, 2025 (in thousands):

(1) Asset management consists of capital expenditures for development related activities primarily associated with recompletions and improvements to our facilities and infrastructure.

(2) Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies.”

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remaining portion of our 2025 capital spending program of $500.0 million to $540.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $120.0 million. However, our ability to (i) generate sufficient cash flows from operations, (ii) obtain future borrowings under the Bank Credit Facility, and (iii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, many of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g., by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to take additional future actions on an opportunistic basis. To address further changes in the financial or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.

Share Repurchase Program — Since the Board initially approved a share repurchase program of $100.0 million on March 20, 2023, the Board has approved increases in share repurchase capacity of $150.0 million on July 22, 2024 and approximately $42.5 million on March 25, 2025, for a total aggregate repurchase capacity of approximately $292.5 million, with approximately $178.0 million remaining under the authorized program as of March 31, 2025. During the three months ended March 31, 2025, we repurchased approximately 2.3 million shares for $22.0 million exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 9.7 million shares under our authorized program for a total principal amount of $114.5 million. The share repurchase program has no set term limits. All repurchased shares are held in treasury.

Repurchases of stock may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.

Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

31

Operating Activities — Cash flows from operating activities changed $171.8 million in the three months ended March 31, 2025 compared to the corresponding period in 2024 primarily attributable to an increase from revenues and a decrease in lease operating expense of $90.5 million. We had a decrease from general and administrative expenses of $35.2 million primarily related to transaction costs for QuarterNorth Acquisition and the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. There was also a decrease in settlements of asset retirement obligations of $18.2 million. Additionally, there were $5.2 million of net cash settlement receipts on derivative instruments during the three months ended March 31, 2025 compared to $3.5 million in net cash settlement payments during the corresponding period in 2024.

Investing Activities — Cash used in investing activities changed $794.3 million in the three months ended March 31, 2025 compared to the corresponding period in 2024. This is primarily due to $916.0 million in cash paid for acquisitions, net of cash acquired, related to the QuarterNorth Acquisition offset by cash proceeds of $142.0 million received from the TLCS Divestiture during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information on the QuarterNorth Acquisition and TLCS Divestiture. Additionally, capital expenditures decreased $17.1 million and contributions to equity method investees decreased of $17.5 million.

Financing Activities — Cash flows related to financing activities changed $859.0 million in the three months ended March 31, 2025 compared to the corresponding period in 2024. During the three months ended March 31, 2025, we cash settled $17.3 million of our common stock repurchased through our share repurchase program. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. During the three months ended March 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,224.5 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition as discussed in our 2024 Annual Report. Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. Furthermore, the Bank Credit Facility had net borrowings of $125.0 million during the corresponding period in 2024.

Overview of Debt Instruments

9.000% Second-Priority Senior Secured Notes — due February 2029 — The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.

9.375% Second-Priority Senior Secured Notes — due February 2031 — The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.

Bank Credit Facility — matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that the Company delivers to the administrative agent of our Bank Credit Facility. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.

Material Cash Requirements

We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements. There have been no material changes to our contractual obligations since those reported in our 2024 Annual Report except for purchase obligations increased from $40.7 million to $85.1 million through 2026 primarily due to increased committed purchase orders to execute planned future drilling activities.

Performance Obligations — As of March 31, 2025, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $42.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2024 Annual Report subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements” and “— Known Trends and Uncertainties — Financial Assurance Market Outlook” for additional information on BOEM’s supplemental bonding requirements and the potential lack of surety bond capacity to comply with BOEM’s financial assurance requirements, which could have a material adverse effect on our business, properties, results of operations and financial condition.

Critical Accounting Estimates

There have been no changes to our critical accounting estimates from those disclosed in our 2024 Annual Report under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.”

Recently Adopted Accounting Standards

Information on Recently Adopted Accounting Standards that impacted our consolidated financial statements and related disclosures is incorporated by reference to Part I, Item 1. “Financial Statements — Note 1 — Organization, Nature of Business and Basis of Presentation.”

Recently Issued Accounting Standards

No accounting standards were issued during the quarterly period ended March 31, 2025 that were material to us. In addition, information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part I, Item 1. “Financial Statements — Note 1 — Organization, Nature of Business and Basis of Presentation.”

For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2024 Annual Report. There have been no material changes from the disclosures presented in our 2024 Annual Report regarding our exposures to certain market risks.

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Based on such evaluation, our principal executive officer and principal financial officer have concluded that as of March 31, 2025, our disclosure controls and procedures were effective at a reasonable assurance level.

Our disclosure controls and procedures are designed at a reasonable assurance level to ensure that the 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 principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our business is subject to a variety of risks and uncertainties. These risks are described elsewhere in this Quarterly Report, including in Part I, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” above, or in our other filings with the SEC, including Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2024. You should carefully consider the risks and other cautionary statements described in this Quarterly Report, our 2024 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. Except for the below, there have been no material changes in our risk factors from those described in our 2024 Annual Report or our other recent SEC filings:

Tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.

In April 2025, the U.S. government announced a baseline tariff of 10% on products from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits. As a result of the new administration’s trade policy, tariffs have increased and may continue to increase our material input costs. We may not be able to adequately mitigate the impact of these increased costs. The imposition of further tariffs by the United States on a broader range of imports, further retaliatory trade measures taken in response to additional tariffs or a global recession could increase costs in our supply chain or reduce demand for oil and natural gas, which would adversely affect our results of operations. The ultimate impact of these trade measures on our business operations and financial results is uncertain and may be affected by various factors, including whether and when such trade measures are implemented, the timing when such measures may become effective, and the amount, scope or nature of such trade measures, and our ability to execute strategies to mitigate the negative impacts.