TALOS ENERGY INC.

Previous wording

The following encompasses significant developments since the filing of our Annual Report on Form 10-K for year ended December 31, 2023:

Current wording

The following encompasses recent developments since the filing of our Annual Report on Form 10-K for year ended December 31, 2024:

Previous wording

Acquisition of Working Interests in Monument Oil Discovery — We executed two separate definitive agreements to acquire a collective 21.4% non-operated working interest in the Monument oil discovery (“Monument Project”) in the Deepwater U.S. Gulf of America located on certain Walker Ridge lease blocks in late July 2024 and early August 2024. First production is expected from the Monument Project by late 2026. On February 20, 2025, we executed a definitive agreement to acquire an additional 8.3% non-operated working interest in the Monument Project for $6.3 million, excluding customary effective date adjustments. An additional aggregate $6.3 million will be paid after certain milestones are achieved. The Company expects to close in March 2025. See additional information in Part IV, Item 1. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures.

Current wording

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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestituresfor additional information.

Previous wording

QuarterNorth Acquisition —On March 4, 2024, we completed the acquisition of QuarterNorth. See Part IV, Item 15. Exhibits and Financial Statement Schedules— Note 3 — Acquisitions and Divestituresfor additional information.

Current wording

QuarterNorth Acquisition —On March 4, 2024, we completed the acquisition of QuarterNorth Energy Inc. (“QuarterNorth”), a privately held U.S. Gulf of America exploration and production company (the “QuarterNorth Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules— Note 3 — Acquisitions and Divestituresfor additional information.

Previous wording

During January 1, 2024 through December 31, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $87.69 per Bbl to a low of $66.73 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $13.20 per MMBtu to a low of $1.21 per MMBtu. 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 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 —Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2024.

Current wording

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 for any commodity that we produce will generally approximate current market prices in the geographic region of production.

Previous wording

Inflation of Cost of Goods, Services and Personnel —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, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. Inflation may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. In 2022 and 2023, the Fed raised its benchmark interest rate 11 times. The Fed wants inflation to return to its 2% goal over time, and even though inflation has declined, it is still high in absolute terms. The Fed lowered its benchmark interest rate three times between September and December 2024 by an aggregate 100 basis points to a new range of 4.25%-4.50% from its 23-year high of 5.25% to 5.50%. In January 2025, the Fed left its benchmark interest rate unchanged as the Fed seeks to gauge where inflation is headed and what policies President Trump may pursue. For example, higher tariffs and tax cuts could push inflation higher, while deregulation could possibly reduce it. Future changes to the benchmark interest rate remain uncertain.

Current wording

Inflation of Cost of Goods, Services and Personnel —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, while during periods of commodity price declines, oilfield costs typically lag and may not adjust downward as fast as oil prices do. Inflation may also result in increases in the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.

Previous wording

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. During 2024, 2023 and 2022 our ceiling test computations for our U.S. oil and gas properties did not result in a write down. At December 31, 2024, the Company’s ceiling test computation was based on SEC pricing of $75.51 per Bbl of oil, $2.45 per Mcf of natural gas and $21.91 per Bbl of NGLs.

Current wording

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. During 2025, our ceiling test calculations resulted in an impairment of our oil and natural gas properties of $454.5 million. During 2024 and 2023 our ceiling test computations for our U.S. oil and gas properties did not result in an impairment. At December 31, 2025, the Company’s ceiling test computation was based on SEC pricing of $65.37 per Bbl of oil, $3.61 per Mcf of natural gas and $19.22 per Bbl of NGLs.

Previous wording

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2024 and ending December 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $67.95 per Bbl of oil, $2.23 per Mcf of natural gas and $19.79 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $420.0 million.

Current wording

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2025 and ending December 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $58.76 per Bbl of oil, $3.26 per Mcf of natural gas and $17.35 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $807 million.

Previous wording

Financial Assurance Requirements —On April 15, 2024, BOEM issued a final rule related to supplemental financial assurance requirements in the OCS entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations.” This rule significantly increases the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the OCS. The final rule provides that BOEM will no longer consider or rely upon the financial strength of predecessors in title in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demand. Per BOEM’s June 28, 2024 news release, BOEM indicated it may take up to 24 months from that date to complete the processing of financial assurance demands. The final rule was challenged in the U.S. District Court for the Western District of Louisiana by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. The implementation of the final rule is not currently stayed and the outcome of these challenges remains uncertain. However, the Trump Administration may seek to suspend, revise or rescind the rule pursuant to Interior Secretary Burgum’s Secretarial Order 3418 dated February 3, 2025, although the substance and timing of such action, if any, cannot be predicted at this time.

Current wording

Financial Assurance Requirements —On April 15, 2024, BOEM issued a final rule related to supplemental financial assurance requirements in the OCS entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations.” This rule significantly increases the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the OCS. The final rule provides that BOEM will no longer consider or rely upon the financial strength of predecessors in title in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demand. The final rule was challenged in the U.S. District Court for the Western District of Louisiana (the “Western Louisiana District Court”) by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. The Western Louisiana District Court granted a stay of the litigation while BOEM pursues efforts to suspend, revise, or rescind the final rule. The Western Louisiana District Court’s order temporarily limits 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.

Previous wording

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined in accordance with both our Bank Credit Facility and Hedging Policy and may be different from what we have done on a historical basis.

Current wording

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined in accordance with both our A&R Credit Agreement and Hedging Policy and may be different from what we have done on a historical basis.

Previous wording

Interest Expense —We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Bank Credit Facility and term-based debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization.

Current wording

Interest Expense —We may finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our bank credit facility and term-based debt. As a result, we may incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization.

Previous wording

Volumetric Analysis — Production volumes increased by 26.3 MBoepd to 92.6 MBoepd for the year ended December 31, 2024. The increase was primarily due to 21.9 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 2.2 MBoepd from the EnVen Acquisition that closed mid-first quarter of 2023. Additionally, we recognized incremental 10.0 MBoepd of production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility and commenced initial production late in the fourth quarter of 2023. These increases were partially offset by a decrease of 4.7 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field. Additionally, there was a decrease of 1.2 MBoepd of production due to disruptions from weather events in the U.S. Gulf of America as well as approximately 1.2 MBoepd of deferred production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.

Current wording

Volumetric Analysis — Production volumes increased by 2.0 MBoepd to 94.6 MBoepd for the year ended December 31, 2025. The increase was primarily due to 6.4 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there were increases of 2.3 MBoepd and 1.2 MBoepd of production from our Katmai West #2 and Sunspear wells, respectively, both of which commenced initial production in June 2025. Production volumes also increased 2.0 MBoepd due to the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. These increases were partially offset by 10.6 MBoepd related to natural decline of the production rate of existing oil and natural gas wells. The absence of weather-related downtime during the 2025 hurricane season compared to the same period in 2024 was favorable to our production volumes.

Previous wording

Total lease operating expenses for the year ended December 31, 2024 increased by approximately $176.4 million, or 45%. The increase is primarily related to lease operating expenses of $147.0 million incurred in connection with assets acquired from the QuarterNorth Acquisition. Additionally, there was a $58.6 million increase in facility and workover expenses primarily attributable to the HP-I and major well workover expenses at the Phoenix Field and Garden Banks 506 Field associated with our historical operations.

Current wording

Total lease operating expenses for the year ended December 31, 2025 decreased by approximately $19.3 million, or 3%. The decrease is primarily related to a $40.2 million decrease in facility and workover expenses primarily related to the HP-1 dry dock and major well workover expenses at the Phoenix Field and the 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 2024.

Previous wording

Depreciation, depletion and amortization expense for the year ended December 31, 2024 increased by approximately $360.0 million, or 54%. This increase was primarily driven by the increased production volumes of 26.3 MBoepd discussed above and to a lesser extent an increase of $2.87 per Boe, or 11% in the depletion rate on our proved oil and natural gas properties due to our amortization base increasing disproportionately to the increase in our reserve base. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures.

Current wording

Depreciation, depletion and amortization expense for the year ended December 31, 2025 increased by approximately $32.7 million, or 3%. This increase was primarily driven by increased production volumes of 2.0 MBoepd discussed above.

Previous wording

Accretion Expense— During the year ended December 31, 2024, we recorded $117.6 million of accretion expense compared to $86.2 million during the year ended December 31, 2023. The change is primarily the result of the increase in accretion associated with the higher asset retirement obligations subject to accretion expense including $15.4 million of incremental accretion expense related to the asset retirement obligations assumed as part of the QuarterNorth Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures for further discussion.

Current wording

Accretion Expense— During the year ended December 31, 2025, we recorded $125.3 million of accretion expense compared to $117.6 million during the year ended December 31, 2024. The change is primarily the result of a $4.4 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition combined with a higher asset retirement obligation subject to accretion expense. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures for additional information.

Previous wording

Talos Low Carbon Solutions Divestiture —On March 18, 2024, we entered into a definitive agreement relating to and subsequently completed the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC, to TotalEnergies E&P USA, Inc. for a purchase price of $125.0 million plus customary reimbursements and adjustments, combined totaling an aggregate of approximately $142.0 million (the “TLCS Divestiture”). The TLCS Divestiture included Talos’s entire CCS business, including its equity investment in three projects along the U.S. Gulf Coast: Bayou Bend CCS LLC (“Bayou Bend”); Harvest Bend CCS LLS; and Coastal Bend CCS LLC. The TLCS Divestiture also entitles Talos to certain contingent payments, of which $4.7 million was received during the year ended December 31, 2024 and $12.5 million is expected to be received during the year ended December 31, 2025. See Part IV, Item 15. Exhibits and Financial Statement Schedules— Note 3 — Acquisitions and Divestitures for additional information.

Current wording

Other Operating (Income) Expense — During the year ended December 31, 2024, we recognized a gain of $100.4 million from the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures for further discussion.

Previous wording

Interest Expense — During the year ended December 31, 2024, we recorded $187.6 million of interest expense compared to $173.1 million during the year ended December 31, 2023. The change is primarily a result of an increase in debt outstanding offset by a lower rate of interest on these instruments. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 —Debt. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan during the year ended December 31, 2024. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures for further discussion.

Current wording

Interest Expense — During the year ended December 31, 2025, we recorded $163.4 million of interest expense compared to $187.6 million during the year ended December 31, 2024. The change is primarily due to a $19.2 million decrease in interest expense related to the Bank Credit Facility as a result of paying off all borrowings under our Bank Credit Facility balance prior to December 31, 2024. 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures for additional information.

Previous wording

Price Risk Management Activities — Price risk management activities for year ended December 31, 2024 resulted in a decrease of approximately $82.4 million, or 102%. The expense of $1.5 million for the year ended December 31, 2024 consisted of $6.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts offset by $4.7 million in cash settlement gains. The income of $80.9 million for the year ended December 31, 2023 consisted of $90.4 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $9.5 million in cash settlement losses.

Current wording

Price Risk Management Activities — The income of $105.5 million for the year ended December 31, 2025 consisted of $81.5 million in cash settlement gains and $24.0 million in non-cash gains from the increase in the fair value of our open derivative contracts. The expense of $1.5 million for the year ended December 31, 2024 consisted of $6.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts offset by $4.7 million in cash settlement gains.

Previous wording

Equity Method Investment (Income) Expense — During the year ended December 31, 2024, we recorded equity losses of $10.3 million. During the year ended December 31, 2023, we recorded $12.1 million of equity losses offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron U.S.A. Inc. (“Chevron”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 —Equity Method Investments for additional information.

Current wording

Equity Method Investment (Income) Expense — During the year ended December 31, 2024, we recorded equity losses of $10.3 million, of which $8.0 million related to our CCS Segment that was divested in March 2024.

Previous wording

Income Tax Benefit (Expense) — During the year ended December 31, 2024, we recorded $5.0 million of income tax expense compared to $60.6 million of income tax benefit during the year ended December 31, 2023. The expense of $5.0 million for the year ended December 31, 2024 is primarily due to a non-cash tax expense of $38.2 million related to the effect of a change in state tax rate, offset with a non-cash tax benefit of $20.3 million related to the partial release of the valuation allowance for certain of our state deferred tax assets and an income tax benefit of $10.7 million related to current year activity inclusive of permanent differences. For the year ended December 31, 2023, we recorded $106.8 million of income tax benefit related to the release of the valuation allowance for our federal deferred tax assets partially offset with an income tax expense of $31.1 million related to current year activity inclusive of permanent differences. The realization of our deferred tax assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 —Income Taxes.

Current wording

Income Tax Benefit (Expense) — During the year ended December 31, 2025, we recorded $109.2 million of income tax benefit compared to $5.0 million of income tax expense during the year ended December 31, 2024. The benefit of $109.2 million for the year ended December 31, 2025 is primarily due to current year activity offset with income tax expense of $28.8 million related to recording a valuation allowance on its U.S. federal deferred tax assets. For the year ended December 31, 2024, we recorded $5.0 million of income tax expense primarily related to state income tax expense of $17.7 million and an income tax benefit of $10.1 million related to current year activity inclusive of nontaxable or nondeductible items. See additional information on the valuation allowance as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 —Income Taxes.

Previous wording

“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.

Current wording

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

Previous wording

EBITDA — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense.

Current wording

EBITDA — Net income (loss) attributable to Talos Energy Inc. plus net income (loss) attributable to noncontrolling interest, plus interest expense, income tax benefit (expense), depreciation, depletion and amortization, and accretion expense.

Previous wording

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.

Current wording

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

Previous wording

For the year ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer as discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 —Employee Benefits Plans and Share-Based Compensation. Transaction expenses include $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisition and Divestitures and Note 11 —Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2024, the amount includes a gain of $100.4 million related to the TLCS Divestiture and a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the 2023 Mexico Divestiture. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the years ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 —Equity Method Investments. For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 15 —Commitments and Contingencies.

Current wording

For the year ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer as discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 —Employee Benefits Plans and Share-Based Compensation. Transaction expenses include $40.4 million in costs related to the EnVen Acquisition, inclusive of $25.3 million for the year ended December 31, 2023. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures and Note 11 —Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2024, the amount includes a gain of $100.4 million related to the TLCS Divestiture and a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the 2023 Mexico Divestiture related to a 49.9% equity interest in Talos Mexico sold to Zamajal. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 —Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million for the year ended December 31, 2023. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 —Equity Method Investments.

Previous wording

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. 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 working capital deficit has decreased since December 31, 2023 primarily due to increased cash and cash equivalents of $74.5 million and redemption $30.0 million in the current portion of principal amount of the 11.75% Notes using the proceeds from the issuance of the Senior Notes. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 —Debt.

Current wording

Our primary sources of liquidity are cash generated by our operations and borrowings under our bank credit facility. Our primary uses of cash are for capital expenditures, operating costs, working capital, debt service, share repurchases, future collateral payments and for general corporate purposes. The cost of borrowing under our bank credit facility is influenced by changes in the federal funds rate. As interest rates increase, it becomes more expensive to borrow money while interest rate cuts make it less expensive to borrow money.

Previous wording

Capital Expenditures —The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2024 (in thousands):

Current wording

Capital and Other Expenditures —The following is a table of our capital and other expenditures, excluding acquisitions, for the year ended December 31, 2025 (in thousands):

Previous wording

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our 2025 Upstream capital spending program of $500.0 million to $540.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $120.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. 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, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.

Current wording

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under our bank credit facility, provide sufficient liquidity to fund our 2026 capital spending program of $500.0 million to $550.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $130.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under our bank credit facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. 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, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.

Previous wording

Common Stock Repurchase Program —Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. During the year ended December 31, 2023 and six months ended June 30, 2024, we repurchased 3.4 million shares for $47.5 million and 3.8 million shares for $42.9 million, respectively. On July 22, 2024, our Board authorized an additional $150.0 million to our previously approved limit increasing the amount remaining under our authorized plan to $159.6 million. During the three months ended September 30, 2024, we repurchased 0.2 million shares for $2.2 million. There were no shares of common stock repurchased during the three months ended December 31, 2024. We have repurchased an aggregate of 7.4 million shares under our authorized program for a total of $92.6 million resulting in approximately $157.4 million remaining under our authorized program as of December 31, 2024. All repurchased shares are held in treasury.

Current wording

Common Stock 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 $80.9 million remaining under the authorized program as of December 31, 2025. During the twelve months ended December 31, 2025, we repurchased 12.6 million shares for $119.1 million exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 20.0 million shares under our authorized program for a total amount of $211.6 million, exclusive of broker commissions. The share repurchase program has no set term limits. All repurchased shares are held in treasury.

Previous wording

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The 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.

Current wording

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The 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. Our share repurchase program is subject to the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations.

Previous wording

Financing Activities —Net cash provided by financing activities increased $350.7 million in 2024 compared to 2023. During the year ended December 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,217.1 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 —Debt for additional information. Additionally, on January 17, 2024, we entered into anunderwritten 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, Bank Credit Facilitynet repayments of $200.0 million were made during the year ended December 31, 2024 due to a management goal to maintain or reduce our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. We had net borrowings from the Bank Credit Facility of $200.0 million during the corresponding period in 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures.

Current wording

Financing Activities —Net cash provided by financing activities increased $600.6 million in 2025 compared to 2024. During the year ended December 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,217.1 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 —Debt for additional information. Additionally, on January 17, 2024, we entered into anunderwritten 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. During the year ended December 31, 2025, we repurchased $119.5 million of our common stock through our common stock repurchase program compared to $45.2 million in the corresponding period in 2024 both amounts inclusive of broker commissions. See subsection above entitled “— Liquidity and Capital Resources — Common Stock Repurchase Program” for additional information. Furthermore, the Bank Credit Facilityhad no activity during the year ended December 31, 2025 compared tonet repayments of $200.0 million during the corresponding period in 2024.

Previous wording

Financing Arrangements —As of December 31, 2024, total debt, net of discount and deferred financing costs, was approximately $1,221.4 million, comprised of our $1,250.0 million aggregate principal amount of the 9.000% Notes and 9.375% Notes (as defined herein) and no outstanding borrowings under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2024. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 —Debt.

Current wording

Financing Arrangements —As of December 31, 2025, total debt, net of discount and deferred financing costs, was approximately $1,226.2 million, comprised of our $1,250.0 million aggregate principal amount of the 9.000% Notes and 9.375% Notes (as defined herein) and no outstanding borrowings under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2025. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 —Debt.

Previous wording

Bank Credit Facility – matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that we deliver to the administrative agent of our Bank Credit Facility. For additional details on our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 —Debt.

Current wording

Bank Credit Facility — We maintained a Bank Credit Facility with a syndicate of financial institutions. The borrowing base was redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that we delivered to the administrative agent of our Bank Credit Facility. As discussed above under “— Recent Developments,” the A&R Credit Agreement replaced the Bank Credit Facility in January 2026. For additional details on our Bank Credit Facility and the A&R Credit Agreement, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 —Debt.

Previous wording

The following table and discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2024 (in thousands):

Current wording

Material Cash Requirements—We are party to various contractual obligations. The following discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2025:

Previous wording

Includes vessel commitments we 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 us will be billed for their working interest share of such costs.

Current wording

Vessel commitments —We have $42.9 million in vessel commitments we 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 us will be billed for their working interest share of such costs. These vessel commitments do not extend beyond a one-year period.

Previous wording

Lease agreement for the HP-I floating production facility in the Phoenix Field.

Current wording

Finance lease —We have $67.6 million in commitments related to our lease agreement for the HP-1 floating production facility in the Phoenix Field, which is utilized in our oil and natural gas development activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 —Leases for additional information, which contemplates renewal period that we are reasonably certain to exercise.

Previous wording

Performance Obligations — As of December 31, 2024, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $42.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

Current wording

Performance Obligations — As of December 31, 2025, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $97.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements and — Financial Assurance Market Outlook” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

Previous wording

We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing.

Current wording

Our proved oil, natural gas and NGL reserves are estimated in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing.

Previous wording

Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. Our reserves at December 31, 2024 were fully engineered by NSAI, while prior year reserve estimates, including as of December 31, 2023 and 2022, were audited by NSAI. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.

Current wording

Estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. Our reserves at December 31, 2025 and 2024 were fully engineered by NSAI and audited by them at December 31, 2023. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.

Previous wording

The depletion of our proved oil and natural gas properties is calculated using the unit-of-production method based on proved oil and gas reserves. If the proved reserves used had been a 10 percent lower, depreciation, depletion and amortization in the year ended December 31, 2024 would have increased by an estimated $108.1 million. Furthermore, the Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. We estimate the net downward revisions of previous reserve volume estimates accounted for approximately $162.0 million of the standardized measure of our total reserves from December 31, 2023 to December 31, 2024. The Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties during the years ended December 31, 2024, 2023 and 2022.

Current wording

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. As a result of the Company’s ceiling test computations, an impairment of its U.S. oil and natural gas properties was recorded during the year ended December 31, 2025 of $454.5 million. If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2025 and ending December 1, 2025 used in the determination of the SEC pricing was 10% lower, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $807 million.

Previous wording

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 P&A and decommission the associated assets.

Current wording

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 and remove or appropriately abandon all production facilities, structures and pipelines following cessation of operations. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to plug, remove or abandon the associated assets.

Previous wording

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.

Current wording

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 decommissioning costs in an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.