Talos Energy Inc.: Form 10-Q for the period ended Sep 30, 2025

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

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

Our Business

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

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

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

Significant Developments

The following significant developments have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2025.

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.

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.

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.

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.

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.

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.”

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.

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.

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

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

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.

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

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

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.

Known Trends and Uncertainties

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

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

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

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil, natural gas and NGLs have been volatile 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.

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

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

In 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.

***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.

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.

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.

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

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

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

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

Financial Assurance Market Outlook — As a result of a number of surety companies leaving the offshore surety market due in part to adverse developments in restructurings and bankruptcies of companies operating in the OCS, there continues to be significant uncertainty in the current market availability of surety bonds for projects and companies operating in the OCS. As such, 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.

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.

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

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

Future Offshore Leasing — Pursuant to OCSLA, the President may withdraw from disposition any of the unleased lands of the OCS. On January 6, 2025, former President Biden issued two memoranda (“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.

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.

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 11th National OCS Program. We cannot determine when the 11th National OCS Program will be finalized, or how many lease sales will be scheduled.

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.

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.

Update on National Marine Fisheries Service’s Gulf of America Revised Biological Opinion — In August 2024, the federal district court for the District of Maryland vacated the 2020 Biological Opinion issued by the National Marine Fisheries Service (“NMFS”), related to oil and gas activities in the Gulf of America. The vacatur was initially effective December 20, 2024, but was later extended to May 21, 2025. On May 20, 2025, NMFS published its new Biological Opinion for the Gulf of America oil and gas program, superseding and replacing all prior biological opinions relating to the program. On the same day, two lawsuits were filed opposing the new Biological Opinion, one by several environmental groups (Sierra Club, the Center for Biological Diversity, Friends of the Earth and Turtle Island Restoration Network) who filed in the federal district court for the District of Maryland, and the other by the State of Louisiana, the American Petroleum Institute and Chevron U.S.A. Inc. who filed in the Western Louisiana District Court. Both lawsuits seek declaratory and injunctive relief. The outcome of these challenges remains uncertain at this time.

On a related matter, in April 2019, NMFS listed the Rice’s whale as endangered under the Endangered Species Act. In July 2023, NMFS proposed to designate approximately 28,300 square miles of the Gulf of America as critical habitat for the Rice’s whale pursuant to a settlement agreement in a lawsuit. On July 3, 2025, an amended settlement agreement was filed with the U.S. District Court for the District of Columbia, which further extends the deadline for NMFS to publish its final rule designating critical habitat for the Rice’s whale to no later than July 15, 2027.

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.

How We Evaluate Our Operations

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

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

Results of Operations

Revenue

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

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

31

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.

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.

Operating Expenses

Lease Operating Expense

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

Three Months Ended 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.

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.

Depreciation, Depletion and Amortization

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

Three Months Ended 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.

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.

General and Administrative Expense

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

Three Months Ended 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.

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.

Miscellaneous

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

Three Months Ended September 30, 2025 and 2024 —

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.”

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.

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.

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.

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

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.

Nine Months Ended September 30, 2025 and 2024 —

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.

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.”

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.

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.

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.

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.

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.

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.

Supplemental Non-GAAP Measure

EBITDA, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc.

“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.

We define these as the following:

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

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

(1) For the three months ended 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.

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

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

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility (as defined herein). Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases, 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.

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.

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

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2025 (in thousands):

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

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

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remaining portion of our 2025 capital spending program of $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.

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.

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.

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

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

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.

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.

Financing Activities — Cash flows related to financing activities changed $705.1 million in the nine months ended September 30, 2025 compared to the corresponding period in 2024. During the nine months ended September 30, 2024, the issuance of the Senior Notes in February 2024 generated $1,220.1 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition as discussed in our 2024 Annual Report. Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock to partially fund the cash portion of the QuarterNorth Acquisition, which generated net proceeds of $387.7 million. During the nine months ended September 30, 2025, we repurchased $103.0 million of our common stock through our share repurchase program compared to $45.2 million in the corresponding period in 2024. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. Furthermore, the Bank Credit Facility had no activity during the nine months ended September 30, 2025 compared to net borrowings of $75.0 million during the corresponding period in 2024. During the nine months ended September 30, 2025, we had deferred payments of $13.0 million primarily related to our acquisition of a 21.4% non-operated working interest in the Monument Project. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.

Overview of Debt Instruments

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

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

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

Material Cash Requirements

We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements. There have been no material changes to our contractual obligations since those reported in our 2024 Annual Report except for (i) an executed vessel commitment that will result in an additional gross commitment of $61.1 million through 2026 and (ii) obligations under the CFSAs that require us to spend an aggregate minimum amount on plugging and abandonment activities of $90.0 million per year for the three years commencing January 1, 2026 and $45.0 million per year for the subsequent two years commencing January 1, 2029.

Performance Obligations — As of September 30, 2025, we had outstanding performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had outstanding letters of credit issued under our Bank Credit Facility totaling $43.3 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2024 Annual Report subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements” and “— Known Trends and Uncertainties — Financial Assurance Market Outlook” for additional information on BOEM’s supplemental bonding requirements and the potential lack of surety bond capacity to comply with BOEM’s financial assurance requirements, which could have a material adverse effect on our business, properties, results of operations and financial condition.

Critical Accounting Estimates

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

Recently Adopted Accounting Standards

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

Recently Issued Accounting Standards

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

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

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Based on such evaluation, our principal executive officer and principal financial officer have concluded that as of September 30, 2025, our disclosure controls and procedures were effective at a reasonable assurance level.

Our disclosure controls and procedures are designed at a reasonable assurance level to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our business is subject to a variety of risks and uncertainties. These risks are described elsewhere in this Quarterly Report, including in Part I, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” above, or in our other filings with the SEC, including Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2024. You should carefully consider the risks and other cautionary statements described in this Quarterly Report, our 2024 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2024 Annual Report or our other recent SEC filings, including our Quarterly Report on Form 10-Q for the quarters ended March 31, 2025 and June 30, 2025.