TALOS ENERGY INC.
For the period ended Sep 30, 2025. Filed Nov 6, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Sep 30, 2025 · Filed Nov 6, 2025
TALO$14.84+1.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-06-30; filed 2025-08-07.
0000950170-25-104296
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-09-30; filed 2025-11-06.
0001193125-25-267455
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 130 previous paragraphs and 135 current paragraphs.
72 unchanged; 45 reworded; 17 added; 12 removed; 1 previous and 1 current paragraphs rearranged.
Tables are not compared: 9 previous and 9 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (17)
Current report
Operational Updates —During the three months ended September 30, 2025, we achieved earlier-than-expected resumption of production at the Sunspear well following an early failure of the surface-controlled subsurface safety valve and a successful exploratory discovery at the Daenerys well.
Current report
Surety Arrangements and Collateral Requirements — In early November 2025, we entered into various collateral funding and security arrangements (“CFSAs”) to establish limits on the amount of aggregate collateral that our surety providers can require us to post. In exchange for our agreement to post maximum amounts of collateral through July 1, 2031 and spend a minimum amount on annual plugging and abandonment activities each year through 2030, the surety providers agreed not to (1) require additional collateral in excess of the agreed and scheduled amounts on existing surety bonds; (2) draw on collateral posted for the benefit of the sureties except under limited circumstances; (3) seek remedies for breaches of any surety agreement that are not an “Event of Default” as defined in the primary CFSA; or (4) cancel, or attempt to cancel, existing bonds unless requested by us.
Current report
For the three years commencing January 1, 2026 and for the subsequent two years commencing January 1, 2029, we are required to spend $90.0 million and $45.0 million on plugging and abandonment activities on an annual basis, respectively, compared to the Company’s 2025 plugging and abandonment budget of $100.0 million to $120.0 million.
Current report
As of September 30, 2025, we had surety bonds totaling approximately $1.5 billion primarily related to plugging and abandonment activities. See Part I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies —Performance Obligations —Subsequent Event ” for the estimated collateral funding commitments under the CFSAs. See Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Financial Assurance Market Outlook.”
Current report
The CFSAs generally contain certain events of default which, if triggered and not cured by us within the cure period, would terminate the standstill period and provide the sureties their full rights under their respective surety and indemnity agreements, including the right to call collateral. Events of default include, but are not limited to, the failure to maintain liquidity of $200.0 million or above a specified credit rating. However, if an event of default were to occur, it is anticipated we would be in a similar position than if we had not entered into the CFSAs given that the surety providers already have the right to demand collateral under existing surety bonds.
Current report
The CFSAs provide a multi-year framework to efficiently address the Company’s collateral commitments and abandonment activities, while strengthening the relationship with our surety providers and supporting our long-term operational strategy.
Current report
Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil, natural gas and NGLs have been volatile and have remained so during 2025 due in part to geopolitical tensions, the global economy, demand fluctuations, oversupply and macroeconomic uncertainty. As such, oil, natural gas and NGL prices have been, and may continue to be, subject to wide fluctuations. Outlooks for crude oil and natural gas prices remain mixed, with some industry sources and analysts expecting prices to soften in 2026 while others anticipate improvement over 2025 levels, reflecting the ongoing unpredictability of global energy markets that will continue to influence the importance of maintaining financial and operational flexibility. Our revenues, cash flow, profitability, access to capital, capital expenditures, and liquidity are directly influenced by commodity prices, and sustained lower prices could adversely affect our financial results. We use hedging instruments to reduce the impact of near-term price volatility. We also anticipate continuing to operate our business in a volatile market by prioritizing high-return development projects, focusing on cost control measures, and maintaining a strong balance sheet to provide financial, operational and capital spending flexibility under a range of price scenarios. We continue to monitor commodity price trends closely and will modify our plans within our strategy as appropriate. See Part I, Item 1. “Financial Statements — Note 5 —Financial Instruments” for additional information regarding our commodity derivative positions as of September 30, 2025.
Current report
In September 2025, the U.S. Federal Reserve (the “Federal Reserve”) lowered its benchmark interest rate by a quarter of a percentage point to a range of 4.00%-4.25%. The Federal Reserve’s decision was driven by a weakening job market, though inflation remains a concern. In October 2025, the Federal Reserve lowered its benchmark interest rate by an additional quarter of a percentage point. Future changes to the benchmark interest rate remain uncertain.
Current report
In early November 2025, we entered into CFSAs to establish limits on the amount of aggregate collateral that our surety providers can require us to post through 2031. See Part I, Item 1. “Financial Statements — Note 13 —Commitment and Contingencies —Performance Obligations —Subsequent Event ” and Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Significant Developments” for additional information.
Current report
Potential Impact of a Prolonged Government Shutdown— The U.S. federal government shut down on October 1, 2025. While we do not currently anticipate that our operations will be significantly impacted, a prolonged federal government shutdown, lapse in federal appropriations or other resulting restrictions on federal agency operations could result in delays or interruptions in future federal lease sales, permitting, inspections, approvals, decommissioning plans, and other agency actions (including actions by BOEM, BSEE, U.S. Coast Guard) upon which our offshore exploration, development and production activities in the U.S. Gulf of America depend. If any such delays are prolonged, it could increase project timelines, cause suspension or postponement of planned drilling plans and capital projects, increase other costs or delay revenues, which could have a material adverse effect on our business, results of operations and cash flows. In addition, a prolonged federal government shutdown could affect supply-chain timing and create macroeconomic uncertainty that affects commodity and capital markets.
Current report
Three Months Ended September 30, 2025 and 2024 — General and administrative expense was relatively flat for the three months ended September 30, 2025 compared to the same period in 2024. There were no significant variances between the periods.
Current report
Other Operating (Income) Expense —During the three months ended September 30, 2025, we derecognized $8.9 million related to a previously recognized deferred payment that was due in October 2025 as significant doubt existed that the payment would be collected. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. During the three months ended September 30, 2024, an incremental $13.5 million gain related to the recognition of contingent consideration from the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”) as well as a $7.0 million increase in fair value of a service credit acquired via the QuarterNorth Acquisition.
Current report
Nine Months Ended September 30, 2025 and 2024 —
Current report
EBITDA, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc.
Current report
Adjusted EBITDA attributable to Talos Energy Inc. — Adjusted EBITDA, less adjustments for noncontrolling interest.
Current report
Surety Agreements and Collateral Requirements — The CFSAs require us to post agreed upon amounts of collateral through July 1, 2031. See Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Significant Developments” for additional information on estimated collateral funding commitments under the CFSAs. The collateral requirements may be secured by cash or letters of credit which will reduce our liquidity.
Current report
Operating Activities — Cash flows from operating activities favorably changed $120.8 million in the nine months ended September 30, 2025 compared to the corresponding period in 2024. The change between periods is primarily attributable to a $157.1 million increase in cash from earnings after non-cash items, as presented in the Condensed Consolidated Statements of Cash Flows under Part I, Item 1. “Financial Statements.” This increase was offset by a $32.3 million decrease in cash due to changes in working capital accounts across all categories of operating assets and liabilities. Working capital at any specific point in time is subject to many variables, including commodity prices, production volumes, and the timing of cash receipts and payments.
Removed paragraphs (12)
Previous report
Operational Updates —Late in the second quarter of 2025, we achieved first production from the Sunspear well. Shortly thereafter, an early failure of the surface-controlled subsurface safety valve was identified. As a precautionary measure, the well was shut in and will require intervention. Following the completion of drilling operations at the Daenerys well, the West Vela drillship will be mobilized to perform the necessary remediation. We expect Sunspear to return to production in October 2025. Additionally, late in the second quarter of 2025, we also achieved first production from the Katmai West #2 well.
Previous report
Twelfth Amendment to Bank Credit Facility — On August 4, 2025, we entered into the Borrowing Base Redetermination Agreement and Twelfth Amendment to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, among other things, (i) decreased both the borrowing base and commitments to $700.0 million and (ii) removed the $50.0 million cap on the amount of unrestricted cash that may be deducted in the calculation of consolidated total debt (used to calculate the Consolidated Total Debt to EBITDAX ratio under the Bank Credit Facility) if, as of the applicable date of determination, each lender’s total exposure is $0.
Previous report
Enhanced Corporate Strategy — On June 17, 2025, we announced an enhanced corporate strategy designed to position the Company as a leading pure-play offshore exploration and production company. The strategy is built on three key pillars. The first pillar targets increased annualized cash flow by improving our existing operations through capital efficiency, margin enhancement, commercial opportunities and general organizational improvements. The second pillar focuses on growth through high-margin organic projects and selective deepwater acquisitions. The third pillar aims to build a long-lived and scaled portfolio in the U.S. Gulf of America and potentially other conventional offshore basins.
Previous report
Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.
Previous report
During the period January 1, 2025 through June 30, 2025, the daily spot prices for NYMEX WTI crude oil ranged from a high of $80.73 per Bbl to a low of $58.50 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.86 per MMBtu to a low of $2.65 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 Btu 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 June 30, 2025.
Previous report
On July 8, 2025, the U.S. Energy Information Administration (“EIA”) published its short-term energy outlook. An increase in the geopolitical risk premium has led the EIA to raise its forecast for crude oil prices over the second half of 2025 primarily attributable to hostilities over Iran’s nuclear program that escalated in mid-June with Israeli and U.S. attacks against Iranian nuclear facilities. The potential for higher oil prices over the second half of this year reflects the importance of the Strait of Hormuz to global oil supply. Concerns among market participants about its potential closure caused a temporary spike in oil prices and volatility in June 2025. Although the geopolitical risk premiums have risen, the EIA still anticipates that global oil inventories will grow significantly over their forecast period and put downward pressure on oil prices. For example, OPEC Plus is in the process of fully restoring 2.2 million barrels per day of voluntary cuts made in November 2023. The EIA expects the NYMEX WTI spot prices to average $65.22 per barrel in 2025 and $54.82 per barrel in 2026. Uncertainty around the status of ongoing trade negotiations between the U.S. and its trading partners could weigh heavily on oil prices going forward.
Previous report
The EIA expects the Henry Hub price to average around $3.70 per MMBtu in 2025 and $4.40 per MMBtu in 2026. This forecasted price increase reflects the expectation that natural gas production will fall slightly in 2026, while liquefied natural gas (“LNG”) exports continue to increase. As such, the EIA expects LNG demand and natural gas production to be key drivers of price in the coming months. For example, LNG exports may be disrupted if tropical storms hit along the Gulf Coast, which could result in more U.S. inventories and lower natural gas prices than expected.
Previous report
In June 2025, the U.S. Federal Reserve (the “Federal Reserve”) left its benchmark interest rate unchanged at a range of 4.25%-4.50%. The Federal Reserve is navigating a complex economic landscape, balancing the potential impact of President Trump’s trade policies, particularly tariffs, with concerns about inflation and unemployment. In July 2025, the Federal Reserve left its benchmark interest rate unchanged for a fifth straight time. Future changes to the benchmark interest rate remain uncertain.
Previous report
On June 27, 2025, BOEM published a Federal Register Notice of Availability of the Proposed Notice of Sale for Gulf of America OCS Oil and Gas Lease Sale 262, the first lease sale included in the 2024-2029 National OCS Program, to be held on December 10, 2025. BOEM expects to publish the Final Notice of Sale for Sale 262 in the Federal Register at least 30 days prior to the December 10, 2025 lease sale date.
Previous report
Six Months Ended June 30, 2025 and 2024 —
Previous report
EBITDA and Adjusted EBITDA
Previous report
Operating Activities — Cash flows from operating activities favorably changed $234.1 million in the six months ended June 30, 2025 compared to the corresponding period in 2024. Working capital at any specific point in time is subject to many variables, including commodity prices, production volumes, and the timing of cash receipts and payments. There was an $86.4 million increase due to changes in working capital accounts largely related to a $60.8 million inflow attributable to accounts receivable between the current period and the corresponding period in 2024 due to a reduction in joint interest receivables and lower commodity prices for trade receivables. There was a $59.5 million increase due to changes in derivative settlements. Net cash received on derivative instruments were $38.5 million during the six months ended June 30, 2025 compared to net cash paid on derivative instruments of $21.0 million during the corresponding period in 2024. Also contributing to the increase in cash flows between periods was a reduction in general and administrative expenses of $44.0 million primarily related to transaction costs for the QuarterNorth Acquisition and the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. Additionally, there was a decrease in settlements of asset retirement obligations of $11.9 million.
Reworded paragraphs (45)
Previous wording
Share Repurchase Program — During the three months ended June 30, 2025, we repurchased 3.8 million shares for $32.6 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board of Directors, resulting in $145.4 million available under the share repurchase program. See “Liquidity and Capital Resources—Share Repurchase Program” for additional information.
Current wording
Share Repurchase Program — During the three months ended September 30, 2025, we repurchased 5.0 million shares for $48.1 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board of Directors (the “Board”), resulting in $97.3 million available under the share repurchase program. See “Liquidity and Capital Resources—Share Repurchase Program” for additional information.
Previous wording
Chief Financial Officer Transition — On May 16, 2025, Sergio L. Maiworm, Jr. informed the Board of Directors that he was resigning from his position as Executive Vice President and Chief Financial Officer of the Company, effective as of June 27, 2025. In connection with and following Mr. Maiworm’s resignation, effective as of June 28, 2025, Gregory Babcock was appointed as Interim Chief Financial Officer to serve until a permanent Chief Financial Officer is appointed by the Board of Directors.
Current wording
Chief Financial Officer Transition — On May 16, 2025, Sergio L. Maiworm, Jr. informed the Board that he was resigning from his position as Executive Vice President and Chief Financial Officer of the Company, effective as of June 27, 2025. In connection with and following Mr. Maiworm’s resignation, effective as of June 28, 2025, Gregory Babcock was appointed as Interim Chief Financial Officer to serve until a permanent Chief Financial Officer was appointed by the Board. On August 12, 2025, the Board appointed Mr. Zachary B. Dailey to serve as the Company’s Executive Vice President and Chief Financial Officer and principal financial officer, effective August 18, 2025.
Previous wording
Acquisition of Incremental Working Interest in Mississippi Canyon Blocks — On July 22, 2025, the Company completed the acquisition of an additional 75.2% and 50% working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively, for $33.7 million of cash paid at closing. The Company currently owns an interest in and operates these developed and producing blocks. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information.
Current wording
Amberjack Acquisition —On July 22, 2025, we completed the acquisition of an additional 75.2% and 50.0% working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively (the “Amberjack Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information.
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, respectively, based on production rates prior to the shut-in.
Previous wording
Impact of Prolonged Increases in Tariffs —We continue to monitor the rapid changes in global trade policies, including tariff increases, and the impact on our business while evaluating actions to mitigate the impact on our business, results of operations, and financial condition. On April 2, 2025, President Donald Trump signed an executive order setting a 10% baseline tariff on imports, with higher rates for countries running trade surpluses with the U.S. By April 9, 2025, a follow-up order paused most of the higher reciprocal tariffs for 90 days. On July 7, 2025, President Trump extended the tariff modifications through August 1, 2025. Public statements from members of the Trump Administration and President Trump, himself, have indicated the negotiations are continuing with various foreign nations, although an extension of the tariff modification deadline beyond the August 1, 2025 deadline cannot be predicted with certainty at this time. Any prolonged increases in global tariffs could have a material impact on our financial condition and results of operations in fiscal year 2025 and beyond.
Current wording
Impact of Prolonged Increases in Tariffs —We continue to monitor changes in global trade policies, including tariff increases, and the impact on our business while evaluating actions to mitigate the impact on our business, results of operations, and financial condition. On September 9, 2025, the U.S. Supreme Court agreed to an expedited review of two cases on tariffs implemented under the International Emergency Economic Powers Act (“IEEPA”) with oral arguments scheduled for early November 2025. President Trump’s previous IEEPA-based tariffs remain in effect pending the outcome of the U.S. Supreme Court decisions. The imposition of additional or any prolonged increases in global tariffs could have a material impact on our financial condition and results of operations in fiscal year 2025 and beyond.
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. As a result of the Company’s ceiling test computations, an impairment of its U.S. oil and natural gas properties was recorded during both the three and six months ended June 30, 2025 of $223.9 million. At June 30, 2025 our ceiling test computation was based on SEC pricing of $70.41 per Bbl of oil, $3.24 per Mcf of natural gas and $21.58 per Bbl of NGLs. No impairments were recorded during the three and six months ended June 30, 2024. See Part I, Item 1. “Financial Statements — Note 3 —Property, Plant and Equipment” for additional information.
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. As a result of the Company’s ceiling test computations, an impairment of its U.S. oil and natural gas properties was recorded during both the three and nine months ended September 30, 2025 of $60.2 million and $284.1 million, respectively. At September 30, 2025 our ceiling test computation was based on SEC pricing of $67.19 per Bbl of oil, $3.48 per Mcf of natural gas and $20.76 per Bbl of NGLs. No impairments were recorded during the three and nine months ended September 30, 2024. See Part I, Item 1. “Financial Statements — Note 3 —Property, Plant and Equipment” for additional information.
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, 2024 and ending June 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $63.37 per Bbl of oil, $2.95 per Mcf of natural gas and $19.60 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been further impaired by approximately an additional $691.6 million assuming all other factors remained constant.
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, 2024 and ending September 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $60.41 per Bbl of oil, $3.16 per Mcf of natural gas and $20.77 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been further impaired by approximately an additional $726.5 million assuming all other factors remained constant.
Previous wording
Financial Assurance Market Outlook — As a result of a number of surety companies leaving the offshore surety market due in part to adverse developments in restructurings and bankruptcies of companies operating in the OCS, there continues to be significant uncertainty in the current market availability of surety bonds for projects and companies operating in the OCS. As such, we may not be able to obtain new surety bonds on commercially reasonable terms or maintain existing bonding without posting collateral. Moreover, under our surety agreements, surety companies have the right to demand collateral. If we are required to provide collateral in the form of cash or letters of credit under our Bank Credit Facility, our liquidity position could be significantly impacted. We cannot predict how much collateral, if any, we may be required to provide.
Current wording
Financial Assurance Market Outlook — As a result of a number of surety companies leaving the offshore surety market due in part to adverse developments in restructurings and bankruptcies of companies operating in the OCS, there continues to be significant uncertainty in the current market availability of surety bonds for projects and companies operating in the OCS. As such, the ability to obtain new surety bonds on commercially reasonable terms without collateral obligations may be limited. Moreover, under our existing surety agreements, surety companies have the right to demand collateral. If we are required to provide the full amount of collateral in the form of cash or letters of credit under our Bank Credit Facility, our liquidity position could be significantly impacted.
Previous wording
Future Offshore Leasing— Pursuant to OCSLA, the President may withdraw from disposition any of the unleased lands of the OCS. On January 6, 2025, former President Biden issued two memoranda under OCSLA that withdrew approximately 625 million acres of the U.S. OCS, including the Eastern Planning Area of the Gulf of America from being considered for new oil or natural gas leases, including for exploration, development and production. However, the Western and Central Planning Areas in the Gulf of America were not included in President Biden’s withdrawal.
Current wording
Future Offshore Leasing— Pursuant to OCSLA, the President may withdraw from disposition any of the unleased lands of the OCS. On January 6, 2025, former President Biden issued two memoranda (“Withdrawal Memoranda”) under OCSLA that withdrew approximately 625 million acres of the U.S. OCS, including the Eastern Planning Area of the Gulf of America from being considered for new oil or natural gas leases, including for exploration, development and production. However, the Western and Central Planning Areas in the Gulf of America were not included in President Biden’s withdrawal.
Previous wording
On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s memoranda and the U.S. Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts and the future of both actions remains undecided. On April 18, 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America. On April 30, 2025, BOEM published a Federal Register notice requesting information and comments on the preparation of the 11 th National OCS Program. The comment period closed on June 16, 2025. We cannot determine when the 11th National OCS Program will be finalized, or how many lease sales will be scheduled.
Current wording
Earlier in 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America. In June 2025, the comment period closed regarding BOEM’s notice requesting information and comments on the preparation of the 11 th National OCS Program. We cannot determine when the 11th National OCS Program will be finalized, or how many lease sales will be scheduled.
Previous wording
The One Big Beautiful Bill Act (“OBBBA”), signed into law by President Trump on July 4, 2025, mandates that the BOEM conduct at least two offshore lease sales annually, of a minimum of 80 million acres (if available) in the Central and Western Gulf of America Planning Areas for the next 15 years, with at least one of these lease sales to be held by December 15, 2025. The OBBBA reduces the royalty rate for Gulf of America leases acquired at these sales back to a minimum of 12.5% (pre-Inflation Reduction Act rates) but not greater than 16.67%.
Current wording
The One Big Beautiful Bill Act (“OBBBA”), signed into law by President Trump on July 4, 2025, mandates that the BOEM conduct at least two offshore lease sales annually, of a minimum of 80 million acres (if available) in the Central and Western Gulf of America Planning Areas for the next 15 years, with at least one of these lease sales to be held by December 15, 2025. The OBBBA reduces the royalty rate for Gulf of America leases acquired at these sales to a minimum of 12.5% (pre-Inflation Reduction Act rates) but not greater than 16.67%. On August 19, 2025, the DOI announced the schedule for the 30 OBBBA-mandated Gulf of America lease sales, the first of which, now named the Big Beautiful Gulf 1 Lease Sale, is set to be held on December 10, 2025. This lease sale will take the place of the previously announced Lease Sale 262, which has been deferred by BOEM. BOEM expects to publish the Final Notice of Sale for this lease sale at least 30 days prior to the scheduled lease sale date. The remaining lease sales are expected to be held each March and August for the years 2026 through 2039, with the last of these mandated Gulf of America lease sales expected in March 2040.
Previous wording
Executive, judicial and/or administrative action resulting in the withdrawal of OCS areas from consideration for new leasing activities or delays in scheduling OCS lease sales, particularly if such actions affect the Western and Central Planning Areas of the Gulf of America in which we currently or seek to operate, could have a material adverse effect on our ability to obtain new OCS leases and develop new assets, as well as negatively impact our financial condition and results of operations.
Current wording
Executive, judicial and/or administrative action resulting in the withdrawal of OCS areas from consideration for new leasing activities or delays in scheduling OCS lease sales, particularly if such actions affect the Western and Central Planning Areas of the Gulf of America in which we currently or seek to operate, could have a material adverse effect on our ability to obtain new OCS leases and develop new assets, as well as negatively impact our financial condition and results of operations. Further, the U.S. federal government shut down on October 1, 2025. A prolonged government shutdown or other resulting restrictions on federal agency operations could result in delays or interruptions in future federal lease sales, and in particular, the upcoming federal lease sales under OBBBA in December 2025 and March 2026. As such, the timing of anticipated lease sales could be uncertain.
Previous wording
Three Months Ended June 30, 2025 and 2024 Volumetric Analysis — Production volumes decreased by 2.2 MBoepd to 93.3 MBoepd. The decrease was primarily due to 7.6 MBoepd well performance and natural production declines. Additionally, there was 3.1 MBoepd in deferred production resulting from maintenance and third party infrastructure downtime primarily attributable to our Green Canyon core area. These decreases were partially offset by an increase of approximately 4.8 MBoepd in deferred production resulting from third party downtime associated with the HP-1 dry dock in our Phoenix Field in the corresponding period in 2024. Additionally, there was 3.8 MBoepd of production from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024.
Current wording
Three Months Ended September 30, 2025 and 2024 Volumetric Analysis — Production volumes decreased by 1.3 MBoepd to 95.2 MBoepd. The decrease was primarily due to 9.4 MBoepd well performance and natural production declines. This decrease was partially offset by 4.2 MBoepd less of deferred production resulting from disruptions due to weather events in the U.S. Gulf of America in the corresponding period in 2024. Additionally, there was 4.0 MBoepd of incremental production from our Katmai West #2 well, which commenced initial production in June 2025.
Previous wording
Six Months Ended June 30, 2025 and 2024 Volumetric Analysis — Production volumes increased by 9.6 MBoepd to 97.1 MBoepd. The increase was primarily due to 11.3 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, production volumes increased 5.3 MBoepd from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024 as well as 2.4 MBoepd in deferred production resulting from third party downtime associated with the HP-1 dry dock in our Phoenix Field in the corresponding period in 2024. These increases were partially offset by a decrease of 8.6 MBoepd due to well performance and natural production declines as well as 2.5 MBoepd in deferred production resulting from maintenance and third party infrastructure downtime.
Current wording
Nine Months Ended September 30, 2025 and 2024 Volumetric Analysis — Production volumes increased by 6.0 MBoepd to 96.5 MBoepd. The increase was primarily due to 8.4 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Production volumes also increased 3.6 MBoepd due to the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. Additionally, there was an increase of 1.4 MBoepd of production from our Katmai West #2 well, which commenced initial production in late June 2025. These increases were partially offset by a decrease of 9.9 MBoepd due to well performance and natural production.
Previous wording
Three Months Ended June 30, 2025 and 2024 — Lease operating expense for the three months ended June 30, 2025 decreased by approximately $20.3 million, or 13%. This was due to an $18.9 million decrease in facility and workover expenses primarily related to the HP-1 at the Phoenix Field and major well workover expenses at Garden Banks 506 Field compared to the same period in 2024.
Current wording
Three Months Ended September 30, 2025 and 2024 — Lease operating expense for the three months ended September 30, 2025 decreased by approximately $29.6 million, or 18%. This was primarily due to a $39.4 million decrease in facility and major well workover expenses at the Gunflint Field compared to the same period in 2024.
Previous wording
Six Months Ended June 30, 2025 and 2024 — Lease operating expense for the six months ended June 30, 2025 decreased by approximately $27.7 million, or 9%. This was due to a $36.8 million decrease in facility and workover expenses primarily related to the HP-1 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 $10.7 million increase in direct lease operating expenses due to the QuarterNorth Acquisition that closed in late first quarter of 2024.
Current wording
Nine Months Ended September 30, 2025 and 2024 — Lease operating expense for the nine months ended September 30, 2025 decreased by approximately $57.3 million, or 13%. This was due to a $47.6 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. Additionally, there was a $32.0 million decrease in facility and workover expenses at the Gunflint Field compared to the same period in 2024. This was partially offset by a $13.0 million increase in direct lease operating expenses due to the QuarterNorth Acquisition that closed in late first quarter of 2024.
Previous wording
Three Months Ended June 30, 2025 and 2024 — Depreciation, depletion and amortization (“DD&A”) expense for the three months ended June 30, 2025 increased by approximately $10.6 million, or 4%. This increase was primarily driven by an increase of $1.98 per Boe, or 7%, in the depletion rate on our proved oil and natural gas properties partially offset by a reduction in production volumes. The change in the DD&A rate between periods caused DD&A expense to increase by $16.8 million and decreased production volumes caused DD&A expense to decrease by $5.7 million.
Current wording
Three Months Ended September 30, 2025 and 2024 — Depreciation, depletion and amortization (“DD&A”) expense for the three months ended September 30, 2025 decreased by approximately $11.6 million, or 4%. This decrease was primarily driven by a decrease of $0.89 per Boe, or 3%, in the depletion rate on our proved oil and natural gas as well as a reduction in production volumes. The change in the DD&A rate between periods and decreased production volumes caused DD&A expense to decrease by $7.8 million and $3.7 million, respectively.
Previous wording
Six Months Ended June 30, 2025 and 2024 — DD&A expense for the six months ended June 30, 2025 increased by approximately $75.7 million, or 16%. This was due to increased production volumes of 9.6 MBoepd discussed above. Additionally, there was an increase of $1.54 per Boe, or 5%, 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.” Increased production volumes and the change in the DD&A rate between periods caused DD&A expense to increase by $48.7 million and $27.1 million, respectively.
Current wording
Nine Months Ended September 30, 2025 and 2024 — DD&A expense for the nine months ended September 30, 2025 increased by approximately $64.1 million, or 9%. This was due to increased production volumes of 6.0 MBoepd discussed above. Additionally, there was an increase of $0.71 per Boe, or 2%, 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.” Increased production volumes and the change in the DD&A rate between periods caused DD&A expense to increase by $45.8 million and $18.7 million, respectively.
Previous wording
Six Months Ended June 30, 2025 and 2024 — General and administrative expense for the six months ended June 30, 2025 decreased by approximately $44.0 million, or 37%. This decrease was primarily driven by Upstream Segment transaction costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $42.7 million or $2.43 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.0 million due to the divestiture of our CCS business. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. This decrease was partially offset by a $4.8 million increase in consulting fees. Additionally, there was an increase in non-cash equity-based compensation of $3.0 million compared to the same period in 2024. See Part I, Item 1. “Financial Statements — Note 9 —Employee Benefits Plans and Share-Based Compensation” for additional information.
Current wording
Nine Months Ended September 30, 2025 and 2024 — General and administrative expense for the nine months ended September 30, 2025 decreased by approximately $44.4 million, or 28%. This decrease was primarily driven by Upstream Segment transaction costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $45.8 million or $2.61 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.0 million due to the divestiture of our CCS business. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. This decrease was partially offset by an increase in non-cash equity-based compensation of $4.7 million compared to the same period in 2024. See Part I, Item 1. “Financial Statements — Note 9 —Employee Benefits Plans and Share-Based Compensation” for additional information.
Previous wording
Impairment of oil and natural gas properties — During the three months ended June 30, 2025, we recorded a $223.9 million impairment of our oil and natural gas properties. The impairment is a result of our ceiling test evaluation as described in Part I, Item 1. “Financial Statements—Note 3—Property, Plant and Equipment.”
Current wording
Impairment of oil and natural gas properties — During the three months ended September 30, 2025, we recorded a $60.2 million impairment of our oil and natural gas properties. The impairment is a result of our ceiling test evaluation as described in Part I, Item 1. “Financial Statements—Note 3—Property, Plant and Equipment.”
Previous wording
Interest Expense —During the three months ended June 30, 2025, we recorded $40.8 million of interest expense compared to $49.0 million during the three months ended June 30, 2024. The change is primarily due to a $7.2 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. “Financial Statements — Note 7 —Debt” for additional information.
Current wording
Interest Expense —During the three months ended September 30, 2025, we recorded $40.8 million of interest expense compared to $46.3 million during the three months ended September 30, 2024. The change is primarily due to a $5.3 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. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for additional information.
Previous wording
Price Risk Management Activities — The income of $86.9 million for the three months ended June 30, 2025 consists of $53.5 million in non-cash gains from the increase in the fair value of our open derivative contracts and $33.3 million in cash settlement gains. 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.
Current wording
Price Risk Management Activities — The income of $4.2 million for the three months ended September 30, 2025 consists of $16.6 million in cash settlement gains offset by $12.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts. 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.
Previous wording
Income Tax (Benefit) Expense — During the three months ended June 30, 2025, we recorded $36.4 million of income tax benefit compared to $1.0 million of income tax benefit during the three months ended June 30, 2024. The income tax benefit recorded during the three months ended June 30, 2025 is primarily due to current year activity offset by the impact of recording a valuation allowance on our U.S. federal deferred tax assets. See additional information in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”
Current wording
Income Tax (Benefit) Expense — During the three months ended September 30, 2025, we recorded $24.2 million of income tax benefit compared to $18.1 million of income tax expense during the three months ended September 30, 2024. See Part I, Item 1. “Financial Statements — Note 10 —Income Taxes” for additional information.
Previous wording
Accretion Expense — During the six months ended June 30, 2025, we recorded $62.9 million of accretion expense compared to $57.6 million during the six months ended June 30, 2024. The change is primarily the result of a $3.4 million increase in accretion associated with the asset retirement obligations assumed as part the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.”
Current wording
Accretion Expense — During the nine months ended September 30, 2025, we recorded $93.7 million of accretion expense compared to $87.1 million during the nine months ended September 30, 2024. The change is largely the result of a $3.9 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” for additional information.
Previous wording
Impairment of oil and natural gas properties — During the six months ended June 30, 2025, we recorded a $223.9 million impairment of our oil and natural gas properties. The impairment is a result of our ceiling test evaluation as described in Part I, Item 1. “Financial Statements—Note 3—Property, Plant and Equipment.”
Current wording
Impairment of oil and natural gas properties — During the nine months ended September 30, 2025, we recorded a $284.1 million impairment of our oil and natural gas properties. The impairment is a result of our ceiling test evaluation as described in Part I, Item 1. “Financial Statements—Note 3—Property, Plant and Equipment.”
Previous wording
Other Operating (Income) Expense —During the six months ended June 30, 2024, we recognized a gain of $86.9 million due to the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information.
Current wording
Other Operating (Income) Expense —During the nine months ended September 30, 2024, we recognized a gain of $100.4 million related to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information.
Previous wording
Interest Expense — During the six months ended June 30, 2025, we recorded $81.7 million of interest expense compared to $99.8 million during the six months ended June 30, 2024. The change is primarily due to a $12.3 million decrease in interest expense as a result of paying off all borrowings under our Bank Credit Facility balance prior to December 31, 2024. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for additional information. Additionally, there was a decrease of $4.9 million of fees associated with an unutilized bridge loan during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information.
Current wording
Interest Expense — During the nine months ended September 30, 2025, we recorded $122.6 million of interest expense compared to $146.1 million during the nine months ended September 30, 2024. The change is primarily due to a $17.6 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 I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information.
Previous wording
Price Risk Management Activities — The income of $71.0 million for the six months ended June 30, 2025 consists of $32.5 million in non-cash gains from the increase in the fair value of our open derivative contracts and $38.5 million in cash settlement gains. 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.
Current wording
Price Risk Management Activities — The income of $75.2 million for the nine months ended September 30, 2025 consists of $55.1 million in cash settlement gains and $20.1 million in non-cash gains from the increase in the fair value of our open derivative contracts. 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 and $14.9 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 primarily attributable to the CCS Segment offset by an $0.4 million equity method income attributable to the Upstream Segment.
Current wording
Equity Method Investment (Income) Expense — During the nine months ended September 30, 2024, we recorded equity losses of $9.1 million primarily attributable to the CCS Segment.
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 additional 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 additional information.
Previous wording
Income Tax (Benefit) Expense — During the six months ended June 30, 2025, we recorded $36.5 million of income tax benefit compared to $22.6 million of income tax benefit during the six months ended June 30, 2024. The income tax benefit is primarily due to current year activity offset by the impact of recording a valuation allowance on our U.S. federal deferred tax assets. 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, 2025, we recorded $60.7 million of income tax benefit compared to $4.4 million of income tax benefit during the nine months ended September 30, 2024. See Part I, Item 1. “Financial Statements — Note 10 —Income Taxes” for additional information.
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 benefit (expense), 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
For the three and six months ended June 30, 2024, transaction expenses included $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. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the six months ended June 30, 2024, the amount included a gain of $86.9 million related to the TLCS Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.”
Current wording
For the three months ended September 30, 2024, transaction expenses included $4.7 million in severance expense related to the departure of the Company’s former President and Chief Executive Officer. 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. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three and nine months ended September 30, 2025, it includes the derecognition of $8.9 million related to a deferred payment that was deemed uncollectible. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.” 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.
Previous 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 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.
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, 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
As a result of the Twelfth Amendment, our Bank Credit Facility currently has a borrowing base of $700.0 million. Giving effect to the borrowing base reduction under the Twelfth Amendment, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $1,014.5 million as of June 30, 2025. Our liquidity has increased since December 31, 2024 due to a higher cash balance offset by reduced borrowing capacity under the Bank Credit Facility. Letters of credit that are outstanding reduce the available revolving credit commitments. The next redetermination of our borrowing base is expected in the fourth quarter of 2025. The borrowing base in reserve-based lending, which is influenced by banking regulations and guidelines, is a dynamic figure subject to regular redeterminations. Changes in reserve estimations (e.g., lower production forecasts or reduced proved reserves), downward adjustments to the lender's internal price deck (i.e., commodity price expectations) and ongoing production can lead to a reduction in the borrowing base, impacting available liquidity under our Bank Credit Facility.
Current wording
Our Bank Credit Facility currently has a borrowing base of $700.0 million. Our available liquidity (cash plus available capacity under the Bank Credit Facility) was $989.4 million as of September 30, 2025. Our liquidity has increased since December 31, 2024 due to a higher cash balance offset by reduced borrowing capacity under the Bank Credit Facility. Letters of credit that are outstanding reduce the available revolving credit commitments. The next redetermination of our borrowing base is expected in the fourth quarter of 2025. The borrowing base in reserve-based lending, which is influenced by banking regulations and guidelines, is a dynamic figure subject to regular redeterminations. Changes in reserve estimations (e.g., lower production forecasts or reduced proved reserves), downward adjustments to the lender's internal price deck (i.e., commodity price expectations) and ongoing production can lead to a reduction in the borrowing base, impacting available liquidity under our Bank Credit Facility.
Previous wording
Capital Expenditures —The following is a table of our capital expenditures, excluding acquisitions, for the six months ended June 30, 2025 (in thousands):
Current wording
Capital Expenditures —The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 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 the remaining portion of our 2025 capital spending program of $490.0 million to $530.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $120.0 million. However, our ability to (i) generate sufficient cash flows from operations, (ii) obtain future borrowings under the Bank Credit Facility, and (iii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, many of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g., by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to take additional future actions on an opportunistic basis. To address further changes in the financial or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.
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 2025 capital spending program of $480.0 million to $520.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $120.0 million. However, our ability to (i) generate sufficient cash flows from operations, (ii) obtain future borrowings under the Bank Credit Facility, and (iii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, many of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g., by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to take additional future actions on an opportunistic basis. To address further changes in the financial or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.
Previous wording
Share Repurchase Program —Since the Board initially approved a share repurchase program of $100.0 million on March 20, 2023, the Board has approved increases in share repurchase capacity of $150.0 million on July 22, 2024 and approximately $42.5 million on March 25, 2025, for a total aggregate repurchase capacity of approximately $292.5 million, with approximately $145.4 million remaining under the authorized program as of June 30, 2025. During the three and six months ended June 30, 2025, we repurchased approximately 3.8 million and 6.1 million shares for $32.6 million and $54.6 million, respectively, exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 13.5 million shares under our authorized program for a total principal amount of $147.1 million. The share repurchase program has no set term limits. All repurchased shares are held in treasury.
Current wording
Share Repurchase Program —Since the Board initially approved a share repurchase program of $100.0 million on March 20, 2023, the Board has approved increases in share repurchase capacity of $150.0 million on July 22, 2024 and approximately $42.5 million on March 25, 2025, for a total aggregate repurchase capacity of approximately $292.5 million, with approximately $97.3 million remaining under the authorized program as of September 30, 2025. During the three and nine months ended September 30, 2025, we repurchased approximately 5.0 million and 11.1 million shares for $48.1 million and $102.7 million, respectively, exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 18.5 million shares under our authorized program for a total amount of $195.2 million, exclusive of broker commissions. The share repurchase program has no set term limits. All repurchased shares are held in treasury.
Previous wording
Investing Activities — Cash used in investing activities changed $770.5 million in the six months ended June 30, 2025 compared to the corresponding period in 2024. This is primarily due to $916.0 million in cash paid for acquisitions, net of cash acquired, related to the QuarterNorth Acquisition offset by cash proceeds of $142.0 million received from the TLCS Divestiture during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information on the QuarterNorth Acquisition and TLCS Divestiture. Additionally, capital expenditures decreased $7.0 million.
Current wording
Investing Activities — Cash used in investing activities changed $763.3 million in the nine months ended September 30, 2025 compared to the corresponding period in 2024. This is primarily due to $936.2 million in cash paid for acquisitions, net of cash acquired, related to the QuarterNorth Acquisition offset by cash proceeds of $142.0 million received from the TLCS Divestiture during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information on the QuarterNorth Acquisition and TLCS Divestiture. Additionally, capital expenditures decreased $6.4 million.
Showing the first 40 of 45 pairs. Open the source sections for the rest.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s Withdrawal Memoranda and the U.S. Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts. On October 2, 2025, the Western District Court of Louisiana found in part for the plaintiffs challenging the Withdrawal Memoranda, which included the States of Louisiana, Alaska, Georgia and Mississippi, the Gulf Energy Alliance and the American Petroleum Institute, and ruled that the Withdrawal Memoranda are unlawful because they exceed the authority granted to the President under OCSLA. The challenge to President Trump’s revocation of the Withdrawal Memoranda remains ongoing.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Three Months Ended June 30, 2025 and 2024 — General and administrative expense for the three months ended June 30, 2025 decreased by approximately $8.8 million, or 18%. This decrease was primarily driven by Upstream Segment transaction costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $12.0 million or $1.42 per Boe. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. This decrease was partially offset by a $3.8 million increase in consulting fees and an increase in non-cash equity-based compensation of $1.6 million compared to the same period in 2024. See Part I, Item 1. “Financial Statements — Note 9 —Employee Benefits Plans and Share-Based Compensation” for additional information.