TALOS ENERGY INC

Previous wording

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”), of which the Company’s only reportable segment was the Upstream Segment. Subsequent to the TLCS Divestiture (as defined herein) and our sale of the entire CCS business, we had one operating segment. See additional information in Part I, Item 1. “Financial Statements — Note 14 —Segment Information.”

Current wording

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”), of which the Company’s only reportable segment was the Upstream Segment. 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. (the “TLCS Divestiture”). Subsequent to the TLCS Divestiture and our sale of the entire CCS business, we had one operating segment. See Part I, Item 1. “Financial Statements — Note 14 —Segment Information” for additional information on our business segments and Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information on the TLCS Divestiture.

Previous wording

The following significant developments have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended March 31, 2024.

Current wording

The following significant developments have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2024, with the SEC on August 8, 2024.

Previous wording

Third Party Planned Downtime —Since our operations are offshore, we are vulnerable to third party 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.

Current wording

Third Party Planned Downtime —Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. For example, 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.

Previous wording

During the three months ended June 30, 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 4.8 MBoepd and 2.4 MBoepd for the three and six months ended June 30, 2024, respectively, based on production rates prior to the shut-in.

Current wording

During the second quarter of 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 1.6 MBoepd for the nine months ended September 30, 2024 based on production rates prior to the shut-in.

Previous wording

During the period January 1, 2024 through June 30, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $87.69 per Bbl to a low of $70.62 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 $1.25 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 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 June 30, 2024.

Current wording

During the period January 1, 2024 through September 30, 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 $1.25 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 September 30, 2024.

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 increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. In addition, the U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could likely cause the U.S. Federal Reserve (the “Fed”) and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business. In 2022 and 2023, the Fed raised its benchmark interest rate 11 times. The latest interest rate hike in July 2023 increased the federal funds rate to a range of 5.25%-5.50%, its highest level since 2001. The Fed wants inflation to return to its 2% goal over time and it is still high in absolute terms. 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 increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. Sustained levels of high 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.

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. For the three and six months ended June 30, 2024 and 2023, we did not recognize an impairment based on the ceiling test computations. At June 30, 2024 our ceiling test computation was based on SEC pricing of $80.82 per Bbl of oil, $2.44 per Mcf of natural gas and $19.86 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. For the three and nine months ended September 30, 2024 and 2023, we did not recognize an impairment based on the ceiling test computations. At September 30, 2024 our ceiling test computation was based on SEC pricing of $80.66 per Bbl of oil, $2.32 per Mcf of natural gas and $19.06 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 July 1, 2023 and ending June 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $72.90 per Bbl of oil, $2.20 per Mcf of natural gas and $17.88 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $166.3 million.

Current wording

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning October 1, 2023 and ending September 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $72.77 per Bbl of oil, $2.10 per Mcf of natural gas and $17.15 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $293.0 million.

Previous wording

BOEM Bonding Rule —On April 15, 2024, BOEM issued its final rule, entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations,” which significantly increases the amount of new supplemental financial assurance required from lessees and grant holders conducting operations on the U.S. federal outer continental shelf (“OCS”). The final rule replaces the prior five-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead requires lessees to meet one of two criteria based on: (1) the credit rating of the lessee or (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. As a result of the new rule, BOEM will no longer consider or rely upon the financial strength of predecessors 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 for full payment of a supplemental financial assurance demand. Per BOEM’s June 28, 2024 news release, BOEM anticipates it will take up to 24 months to complete the processing of financial assurance demands for execution.

Current wording

BOEM Bonding Rule —On April 15, 2024, BOEM issued its final rule, entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations,” which significantly increases the amount of new supplemental financial assurance required from lessees and grant holders conducting operations on the U.S. federal outer continental shelf (“OCS”). The final rule replaces the prior five-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead requires lessees to meet one of two criteria based on: (1) the credit rating of the lessee or (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. As a result of the new rule, BOEM will no longer consider or rely upon the financial strength of predecessors 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 for full payment of a supplemental financial assurance demand. Per BOEM’s June 28, 2024 news release, BOEM anticipates it will take up to 24 months to complete the processing of financial assurance demands for execution. 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. Although implementation of the rule is not currently stayed, the outcome of these challenges remain uncertain.

Previous wording

Three Months Ended June 30, 2024 and 2023 Volumetric Analysis —Production volumes increased by 25.3 MBoepd to 95.5 MBoepd. The increase was primarily due to 28.1 MBoepd of production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there was 10.5 MBoepd production from our operated Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023. These increases were partially offset by a decrease of 7.7 MBoepd due to well performance and natural production declines. Additionally, we deferred approximately 4.8 MBoepd of production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.

Current wording

Three Months Ended September 30, 2024 and 2023 Volumetric Analysis —Production volumes increased by 32.8 MBoepd to 96.5 MBoepd. The increase was primarily due to 26.2 MBoepd of production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there was 9.5 MBoepd production from our operated Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023 as well as 2.9 MBoepd production from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. These increases were partially offset by a decrease of 4.2 MBoepd of production due to disruptions from weather events in the U.S. Gulf of Mexico. Additionally, there was a decrease of approximately 2.7 MBoepd due to well performance and natural production declines.

Previous wording

Six Months Ended June 30, 2024 and 2023 Volumetric Analysis —Production volumes increased by 20.6 MBoepd to 87.5 MBoepd. The increase was primarily due to 17.7 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, production volumes increased 10.3 MBoepd production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023. These increases were partially offset by a decrease of 5.9 MBoepd due to well performance and natural production declines. Additionally, we deferred approximately 2.4 MBoepd of production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.

Current wording

Nine Months Ended September 30, 2024 and 2023 Volumetric Analysis —Production volumes increased by 24.7 MBoepd to 90.5 MBoepd. The increase was primarily due to 20.6 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 2.1 MBoepd from the EnVen Acquisition that closed mid-first quarter of 2023. Additionally, production volumes increased 10.0 MBoepd production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023. These increases were partially offset by decreases of 5.0 MBoepd due to well performance and natural production declines as well as 1.4 MBoepd due to disruptions from weather events in the U.S. Gulf of Mexico. Additionally, we deferred approximately 1.6 MBoepd of production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.

Previous wording

Three Months Ended June 30, 2024 and 2023 — Lease operating expense for the three months ended June 30, 2024 increased by approximately $56.1 million, or 55%. This increase was primarily related to lease operating expenses of $40.0 million incurred in connection with assets acquired in the QuarterNorth Acquisition. Additionally, there was a $16.9 million increase in facility and workover expense primarily related to the HP-I compared to the same period in 2023.

Current wording

Three Months Ended September 30, 2024 and 2023 — Lease operating expense for the three months ended September 30, 2024 increased by approximately $59.8 million, or 58%. This increase was primarily related to lease operating expenses of $63.8 million incurred in connection with assets acquired in the QuarterNorth Acquisition. Included in the increase during the three months ended September 30, 2024 is $33.1 million in facility and well workover expenses at the Gunflint Field.

Previous wording

Six Months Ended June 30, 2024 and 2023 — Lease operating expense for the six months ended June 30, 2024 increased by approximately $110.0 million, or 60%. This increase was related to lease operating expenses of $52.8 million incurred in connection with assets acquired in the QuarterNorth Acquisition as well as a $10.4 million increase in lease operating expenses due to the EnVen Acquisition that closed in mid-first quarter 2023. Additionally, there was a $52.8 million increase in facility and workover expense primarily related to the HP-I and major well workover expenses at the Phoenix Field and the Garden Banks 506 Field. These increases were partially offset by a $3.2 million increase in production handling reimbursements from certain third parties related to our historical operations.

Current wording

Nine Months Ended September 30, 2024 and 2023 — Lease operating expense for the nine months ended September 30, 2024 increased by approximately $169.8 million, or 59%. This increase was related to lease operating expenses of $116.7 million incurred in connection with assets acquired in the QuarterNorth Acquisition as well as a $10.1 million increase in lease operating expenses due to the EnVen Acquisition that closed in mid-first quarter 2023.

Previous wording

Three Months Ended June 30, 2024 and 2023 — Depreciation, depletion and amortization expense for the three months ended June 30, 2024 increased by approximately $89.3 million, or 53% due to increased production volumes, which are described above. Additionally, the depletion rate increased by $3.30 per Boe, or 13%, on our proved oil and natural gas properties.

Current wording

Three Months Ended September 30, 2024 and 2023 — Depreciation, depletion and amortization expense for the three months ended September 30, 2024 increased by approximately $110.9 million, or 68% due to increased production volumes, which are described above. Additionally, the depletion rate increased by $3.11 per Boe, or 11%, on our proved oil and natural gas properties.

Previous wording

Six Months Ended June 30, 2024 and 2023 — Depreciation, depletion and amortization expense for the six months ended June 30, 2024 increased by approximately $157.6 million, or 50%. This was due to an increase of $3.71 per Boe, or 14%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the QuarterNorth Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.”

Current wording

Nine Months Ended September 30, 2024 and 2023 — Depreciation, depletion and amortization expense for the nine months ended September 30, 2024 increased by approximately $268.5 million, or 56%. This was due to an increase of $3.54 per Boe, or 13%, 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. Our amortization base increased primarily due to the proved properties acquired as part of the QuarterNorth Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.”

Previous wording

Three Months Ended June 30, 2024 and 2023 —General and administrative expense for the three months ended June 30, 2024 increased by approximately $15.1 million, or 45%. This increase was primarily related to Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $11.5 million or $1.33 per Boe. Additionally, there was an increase in payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. These increases were partially offset by a decrease in the Upstream Segment transaction costs for the EnVen Acquisition of $2.7 million or $0.43 per Boe. Additionally, the CCS Segment expenses decreased by $2.4 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.

Current wording

Three Months Ended September 30, 2024 and 2023 —General and administrative expense for the three months ended September 30, 2024 increased by approximately $17.0 million, or 68%. This increase was primarily due to an increase in contractor and payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. Additionally, there was an increase related to Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $3.1 million or $0.35 per Boe as well as an increase in non-cash equity-based compensation of $2.9 million. These increases were partially offset by a decrease in the CCS Segment expenses of $2.5 million due to the TLCS Divestiture. Additionally, Upstream Segment transaction costs for the EnVen Acquisition decreased $1.5 million or $0.26 per Boe. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.

Previous wording

Six Months Ended June 30, 2024 and 2023 —General and administrative expense for the six months ended June 30, 2024 increased by approximately $21.7 million, or 23%. This increase was primarily related to the Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $42.1 million or $2.64 per Boe. Unallocated corporate reflects an increase in transaction costs and severance costs of $9.0 million related to the TLCS Divestiture. Additionally, there was an increase in payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. These increases were partially offset by a decrease in the Upstream Segment transaction costs for the EnVen Acquisition of $38.2 million or $3.15 per Boe. Additionally, the CCS Segment expenses decreased by $3.8 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.

Current wording

Nine Months Ended September 30, 2024 and 2023 —General and administrative expense for the nine months ended September 30, 2024 increased by approximately $38.7 million, or 32%. This increase was primarily related to the Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $45.2 million or $2.84 per Boe. Unallocated corporate reflects an increase in transaction costs and severance costs of $8.4 million related to the TLCS Divestiture. Additionally, there was an increase in contractor and payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. These increases were partially offset by a decrease in the Upstream Segment transaction costs for the EnVen Acquisition of $39.7 million or $2.21 per Boe. Additionally, the CCS Segment expenses decreased by $6.3 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.

Previous wording

Accretion Expense —During the three months ended June 30, 2024, we recorded $30.7 million of accretion expense compared to $22.8 million during the three months ended June 30, 2023. The change is primarily the result of a $4.5 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”

Current wording

Accretion Expense —During the three months ended September 30, 2024, we recorded $29.4 million of accretion expense compared to $21.3 million during the three months ended September 30, 2023. The change is primarily the result of a $4.6 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”

Previous wording

Price Risk Management Activities — The income of $2.3 million for the three months ended June 30, 2024 consists of $19.8 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $17.5 million in cash settlement losses. The income of $26.2 million for the three months ended June 30, 2023 consists of $18.0 million in non-cash gains from the increase in the fair value of our open derivative contracts and $8.2 million in cash settlement gains.

Current wording

Price Risk Management Activities — The income of $126.3 million for the three months ended September 30, 2024 consists of $120.2 million in non-cash gains from the increase in the fair value of our open derivative contracts and $6.1 million in cash settlement gains. The expense of $98.8 million for the three months ended September 30, 2023 consists of $92.5 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $6.3 million in cash settlement losses.

Previous wording

Income Tax (Benefit) Expense —During the six months ended June 30, 2024, we recorded $22.6 million of income tax benefit compared to $39.7 million of income tax benefit during the six months ended June 30, 2023. The income tax benefit is primarily due to current year activity offset by the impact from permanent differences. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”

Current wording

Income Tax (Benefit) Expense — During the three months ended September 30, 2024, we recorded $18.1 million of income tax expense compared to $15.9 million of income tax benefit during the three months ended September 30, 2023. The income tax expense recorded during the three months ended September 30, 2024 is primarily due to current year activity offset by the impact from permanent differences. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”

Previous wording

Accretion Expense —During the six months ended June 30, 2024, we recorded $57.6 million of accretion expense compared to $42.2 million during the six months ended June 30, 2023. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of both the EnVen Acquisition and QuarterNorth Acquisition and upward revisions of our asset retirement obligations. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”

Current wording

Accretion Expense —During the nine months ended September 30, 2024, we recorded $87.1 million of accretion expense compared to $63.4 million during the nine months ended September 30, 2023. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of both the EnVen Acquisition and QuarterNorth Acquisition and upward revisions of our asset retirement obligations. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”

Previous wording

Other Operating (Income) Expense —During the six months ended June 30, 2024, we recognized a gain of $86.9 million on the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.

Current wording

Other Operating (Income) Expense — During the nine months ended September 30, 2024, we recognized a gain of $100.4 million on the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion. During the nine months ended September 30, 2023, we recognized a gain of $66.2 million related to the deconsolidation of Talos Mexico partially offset by $9.5 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency.

Previous wording

Interest Expense —During the six months ended June 30, 2024, we recorded $99.8 million of interest expense compared to $83.2 million during the six months ended June 30, 2023. The change is primarily the result of an increase in debt outstanding offset by a lower rate of interest on these instruments. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.

Current wording

Interest Expense —During the nine months ended September 30, 2024, we recorded $146.1 million of interest expense compared to $128.9 million during the nine months ended September 30, 2023. The change is primarily the result of an increase in debt outstanding offset by a lower rate of interest on these instruments. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.

Previous wording

Price Risk Management Activities —The expense of $84.8 million for the six months ended June 30, 2024 consists of $63.8 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $21.0 million in cash settlement losses. The income of $85.1 million for the six months ended June 30, 2023 consists of $89.3 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by $4.2 million in cash settlement losses.

Current wording

Price Risk Management Activities —The income of $41.5 million for the nine months ended September 30, 2024 consists of $56.5 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $14.9 million in cash settlement losses. The expense of $13.7 million for the nine months ended September 30, 2023 consists of $3.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $10.5 million in cash settlement losses.

Previous wording

Equity Method Investment (Income) Expense — During the six months ended June 30, 2024, we recorded equity losses of $8.9 million partially offset by $0.4 million equity method income. During the six months ended June 30, 2023, we recorded equity losses of $3.2 million offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron. See Part I, Item 1. “Financial Statements — Note 12 —Related Party Transactions” for additional information.

Current wording

Equity Method Investment (Income) Expense — During the nine months ended September 30, 2024, we recorded equity losses of $9.1 million. During the nine months ended September 30, 2023, we recorded an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend CCS LLC (“Bayou Bend”) by Chevron U.S.A. Inc. (“Chevron”) offset by equity losses of $5.6 million.

Previous wording

Other (Income) Expense— During the six months ended June 30, 2024, we recorded a $60.3 million loss on extinguishment of debt in conjunction with 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”). See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.

Current wording

Other (Income) Expense— During the nine months ended September 30, 2024, we recorded a $60.3 million loss on extinguishment of debt in conjunction with 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”). See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.

Previous wording

Income Tax (Benefit) Expense — During the three months ended June 30, 2024, we recorded $1.0 million of income tax benefit compared to $6.9 million of income tax expense during the three months ended June 30, 2023. The income tax benefit recorded during the three months ended June 30, 2024 is primarily due to a non-cash income tax benefit recognized in the Company’s state deferred tax liability. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”

Current wording

Income Tax (Benefit) Expense —During the nine months ended September 30, 2024, we recorded $4.4 million of income tax benefit compared to $55.5 million of income tax benefit during the nine months ended September 30, 2023. The income tax benefit is primarily due to current year activity offset by the impact from permanent differences and a non-cash income tax benefit recognized in the Company’s state deferred tax liability. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”

Previous wording

For the three and six months ended June 30, 2024, transaction expenses include $9.3 million and $37.4 million, respectively, in costs related to the QuarterNorth Acquisition, inclusive of $8.1 million and $22.3 million, respectively, in severance expense. For the six months ended June 30, 2024, transaction expenses include $9.0 million in costs related to the TLCS Divestiture, inclusive of $3.7 million in severance expense. For the three and six months ended June 30, 2023, transaction expenses included $2.7 million and $37.9 million, respectively, in costs related to the EnVen Acquisition, inclusive of $1.4 million and $24.0 million, respectively, in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” and “Note 9 —Employee Benefits Plans and Share-Based Compensation.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the six months ended June 30, 2024, it includes 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.” For the six months ended June 30, 2023, it includes an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron.

Current wording

For the three months ended September 30, 2024, transaction expenses include $4.7 million in severance expense related to the departure of the Company’s former President and Chief Executive Officer as discussed in Part I, Item 1. “Financial Statements — Note 9 —Employee Benefits Plans and Share-Based Compensation.” For the nine months ended September 30, 2024, transaction expenses include $38.8 million in costs related to the QuarterNorth Acquisition, inclusive of $22.3 million in severance expense, and $8.4 million in costs related to the TLCS Divestiture, inclusive of a net $2.9 million in severance expense. For the three and nine months ended September 30, 2023, transaction expenses included $1.5 million and $39.4 million, respectively, in costs related to the EnVen Acquisition, inclusive of $0.9 million and $24.9 million, respectively, in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” and “Note 9 —Employee Benefits Plans and Share-Based Compensation.” 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 and nine months ended September 30, 2024, it includes a gain of $13.5 million and $100.4 million related to the TLCS Divestiture, respectively. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.” Additionally, for the three and nine months ended September 30, 2024, it includes a gain of $7.0 million and $9.5 million, respectively, related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the three and nine months ended September 30, 2023, the amount includes a $66.2 million gain related to the deconsolidation of Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”). For the nine months ended September 30, 2023, the amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million.

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 borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed made it more expensive to borrow money. As of June 30, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $738.7 million.

Current wording

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 borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed made it more expensive to borrow money. As of September 30, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $842.9 million.

Previous wording

Capital Expenditures —The following is a table of our capital expenditures, excluding acquisitions, for the six months ended June 30, 2024 (in thousands):

Current wording

Capital Expenditures —The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2024 (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 the remaining portion of our 2024 Upstream capital spending program of $570.0 million to $600.0 million and plugging & abandonment and decommissioning obligations of $90.0 million to $100.0 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.

Current 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 the remaining portion of our 2024 Upstream capital spending program of $510.0 million to $530.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $110.0 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.

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 three months ended June 30, 2024, we repurchased approximately 3.8 million shares for $42.9 million. As of June 30, 2024, there is $9.7 million remaining under the authorized program. In July 2024, our Board of Directors authorized an increase of $150.0 million to the previously approved limit increasing the amount remaining under the authorized plan to $159.7 million. All repurchased shares are held in treasury. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022 applies to our share repurchase program. We do not currently anticipate incurring any excise tax in 2024 based on the fair market value of the common stock issued during 2024. See Part II, Item 2. “Unregistered Sales of Equity Securities and Use of Proceeds” for additional information.

Current wording

Common Stock Repurchase Program — Our Board authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. In July 2024, our Board authorized an increase of $150.0 million to the previously approved limit increasing the amount remaining under the authorized plan to $159.7 million. All repurchased shares are held in treasury. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022 applies to our share repurchase program. We do not currently anticipate incurring any excise tax in 2024 based on the fair market value of the common stock issued during 2024.

Previous wording

Operating Activities — Net cash provided by operating activities increased $108.7 million in the six months ended June 30, 2024 compared to the corresponding period in 2023 primarily attributable to an increase from revenues offset with an increase in lease operating expense of $179.3 million and an increase in net cash paid on derivatives of $16.9 million.

Current wording

Operating Activities — Net cash provided by operating activities increased $270.4 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023 primarily attributable to an increase from revenues offset with an increase in lease operating expense of $245.7 million.

Previous wording

Investing Activities — Net cash used in investing activities increased $750.3 million in the six months ended June 30, 2024 compared to the corresponding period in 2023 primarily due to cash paid for the QuarterNorth Acquisition of $916.0 million, net of cash acquired. This was offset by cash proceeds of $142.0 million from the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. Additionally, capital expenditures decreased $29.5 million.

Current wording

Investing Activities — Net cash used in investing activities increased $776.2 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023 primarily due to cash paid for acquisitions of $936.2 million, net of cash acquired, of which $916.0 million related to the QuarterNorth Acquisition. Cash proceeds of $142.0 million was received from the TLCS Divestiture during the nine months ended September 30, 2024 compared to $66.2 million of net proceeds from the sale of property and equipment during the corresponding period in 2023. 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 $83.3 million.

Previous wording

Financing Activities —Cash flow from financing activities changed $573.4 million in the six months ended June 30, 2024 compared to the corresponding period in 2023. During the six months ended June 30, 2024, the issuance of the New Senior Notes in February 2024 generated $1,222.6 million after deferred financing costs. The net proceeds from the New 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 I, Item 1. “Financial Statements — Note 7 —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.

Current wording

Financing Activities —Cash flow from financing activities changed $449.4 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023. During the nine months ended September 30, 2024, the issuance of the New Senior Notes in February 2024 generated $1,220.1 million after deferred financing costs. The net proceeds from the New 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 I, Item 1. “Financial Statements — Note 7 —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 $75.0 million were made during the nine months ended September 30, 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 $215.0 million during the corresponding period in 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures.

Previous wording

This table does not include our estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties with a carrying value of $1,158.8 million as of June 30, 2024. For additional information regarding these liabilities, please see Part I, Item 1. “Financial Statements — Note 8 —Asset Retirement Obligations.” Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies.”

Current wording

This table does not include our estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties with a carrying value of $1,189.9 million as of September 30, 2024. For additional information regarding these liabilities, please see Part I, Item 1. “Financial Statements — Note 8 —Asset Retirement Obligations.” Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies.”

Previous wording

Performance Obligations —As of June 30, 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 Mexico. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $39.1 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for further information on the Bank Credit Facility.

Current wording

Performance Obligations —As of September 30, 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 Mexico. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $42.7 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for further information on the Bank Credit Facility.