TALOS ENERGY INC.
For the period ended Mar 31, 2025. Filed May 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.
Mar 31, 2025 · Filed May 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 2024-09-30; filed 2024-11-12.
0000950170-24-125580
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-03-31; filed 2025-05-06.
0000950170-25-063785
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 127 previous paragraphs and 110 current paragraphs.
48 unchanged; 38 reworded; 23 added; 37 removed; 4 previous and 1 current paragraphs rearranged.
Tables are not compared: 10 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 (23)
Current report
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.
Current report
Appointment of President and Chief Executive Officer— Effective March 1, 2025, Mr. Paul Goodfellow was appointed President and Chief Executive Officer, principal executive officer and as an executive member of the Board.
Current report
Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an incremental 8.3% working interest in the Monument oil discovery in the U.S. Gulf of America located on certain Walker Ridge lease blocks. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures”for more information.
Current report
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:
Current report
• Deepwater Operations
Current report
• Oil Spill Response Plan
Current report
Recent developments in U.S. trade policy and oil production have led to a significant drop in crude oil prices during April. On April 2, 2025, President Trump signed an Executive Order announcing 10% tariffs on imports from all countries, with higher tariffs initially imposed on some countries. On April 3, 2025, OPEC Plus announced that some countries will start production increases in May 2025 that were originally set for July 2025. Following these announcements, crude oil prices fell sharply. On April 10, 2025, the U.S. Energy Information Administration (“EIA”) published its short-term energy outlook, with expectations that prices for crude oil and other commodities will continue to experience significant volatility as market participants assess the effects of trade policies. The EIA expects global oil inventories will increase starting in the middle of 2025 as OPEC Plus members unwind production cuts, production grows in non-OPEC countries, and oil demand growth slows. The effect that new or additional tariffs will have on global economic activity and associated oil demand is still highly uncertain and could weigh heavily on crude oil prices going forward. The implementation of energy-sector sanctions on Russia and Iran, as well as the wind down of Chevron’s Venezuela oil exports, have increased crude oil price volatility in the short term while markets and trade patterns adjust. The EIA expects the NYMEX WTI spot prices to average $63.88 per barrel in 2025 and $57.48 per barrel in 2026 and Henry Hub price to average around $4.27 per MMBtu in 2025 and $4.60 per MMBtu in 2026.
Current report
In March 2025, the U.S. Federal Reserve (the “Fed”) left its benchmark interest rate unchanged at a range of 4.25%-4.50% although the Fed indicated it still anticipates reducing borrowing costs by half a percentage point by the end of 2025 in the context of slowing economic growth and, eventually, a downturn in inflation. Future changes to the benchmark interest rate remain uncertain.
Current report
Impact of Prolonged Increases in Tariffs —We continue to monitor the rapid changes in global trade policies, including tariff increases, and the impact on our business while evaluating actions to mitigate the impact on our business, results of operations, and financial condition. Any prolonged increases in global tariffs could have a material impact on our financial condition and results of operations in fiscal year 2025 and beyond. The recent tariffs may increase inflation in the near term, lead to slower growth for the U.S. economy and increase the probability of a U.S. recession.
Current report
Update on Financial Assurance Rule— Effective June 29, 2024, BOEM adopted a final rule which significantly increases the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the Outer Continental Shelf (“OCS”). The final rule adopted a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demands. The final rule was challenged in the U.S. District Court for the Western District of Louisiana (the “District Court”) by multiple oil and gas industry groups and the States of Mississippi, Louisiana and Texas and the District Court granted a stay of the litigation while the agency pursues efforts to suspend, revise, or rescind the final rule. The District Court’s order temporarily limits BOEM’s full implementation of the final rule by limiting BOEM’s ability to seek supplemental financial assurance to cases of sole liability properties and certain non-sole liability properties that are held by owners who are not financially strong, as described in the final rule, and that have no co-owners or predecessors who are financially strong.
Current report
On May 2, 2025, the Department of the Interior (“DOI”) announced its intent to revise and develop a new rule that is consistent with the Trump Administration’s 2020 proposed rule on financial assurance. The specific substance and timing of a revised rule cannot be predicted at this time. However, we anticipate that the new revised rule will revert to BOEM’s decades-long policy of considering the financial strength of both co-owners and predecessors in title when determining whether supplemental financial assurance is required and reduce the credit rating required under the current final rule for financial assurance waivers. In light of these expectations, we anticipate the amount we would be required to bond under the revised rule would be significantly less than under the final rule.
Current report
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.
Current report
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 report
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.
Current report
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.
Current report
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 report
On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s memoranda and the U.S. Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts and the future of both actions remains undecided. On April 18, 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America, the first of which is expected to be held by the end of 2025. We cannot determine when the 11th National OCS Program will be initiated, or how many lease sales will be scheduled.
Current report
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 report
Three Months Ended March 31, 2025 and 2024 — Lease operating expense for the three months ended March 31, 2025 decreased by approximately $7.4 million, or 5%. This was primarily related to a $30.8 million decrease in workover expenses at the Phoenix Field and Garden Banks 506 Field compared to the same period in 2024. This was partially offset by a $16.9 million increase in direct lease operating expenses due to the QuarterNorth Acquisition that closed in late first quarter of 2024. Additionally, there was a $4.6 million decrease in production handling fees related to reimbursements for costs from certain third parties related to our historical operations.
Current report
Our Bank Credit Facility currently has a borrowing base of $925.0 million but is subject to an $800.0 million availability cap. As of March 31, 2025, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $960.2 million or $1,085.2 million inclusive of the $125.0 million availability cap requiring certain lender approval. Letters of credit that are outstanding reduce the available revolving credit commitments. If oil prices remain at current levels or we are unable to replace proved reserves either through acquisitions or new drilling activity, our borrowing base will likely be reduced at our next redetermination which is expected in the second quarter of 2025 and our available liquidity may be negatively impacted unless offset by cash generated from our operating activities.
Current report
Share Repurchase Program —Since the Board initially approved a share repurchase program of $100.0 million on March 20, 2023, the Board has approved increases in share repurchase capacity of $150.0 million on July 22, 2024 and approximately $42.5 million on March 25, 2025, for a total aggregate repurchase capacity of approximately $292.5 million, with approximately $178.0 million remaining under the authorized program as of March 31, 2025. During the three months ended March 31, 2025, we repurchased approximately 2.3 million shares for $22.0 million exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 9.7 million shares under our authorized program for a total principal amount of $114.5 million. The share repurchase program has no set term limits. All repurchased shares are held in treasury.
Current report
Operating Activities — Cash flows from operating activities changed $171.8 million in the three months ended March 31, 2025 compared to the corresponding period in 2024 primarily attributable to an increase from revenues and a decrease in lease operating expense of $90.5 million. We had a decrease from general and administrative expenses of $35.2 million primarily related to transaction costs for QuarterNorth Acquisition and the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information. There was also a decrease in settlements of asset retirement obligations of $18.2 million. Additionally, there were $5.2 million of net cash settlement receipts on derivative instruments during the three months ended March 31, 2025 compared to $3.5 million in net cash settlement payments during the corresponding period in 2024.
Current report
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.”
Removed paragraphs (37)
Previous report
In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.
Previous report
Limited Duration Stockholder Rights Agreement — On October 1, 2024, our Board of Directors (the “Board”) adopted a stockholder rights agreement (the “Rights Agreement”) and declared a dividend distribution of one preferred share purchase right on each outstanding share of the Company’s common stock, par value $0.01 per share (the “Common Stock”), which became payable on October 11, 2024. The Board adopted the Rights Agreement to deter any future efforts by one person or a group to acquire actual, de facto or negative control of the Company through open market accumulation, or other tactics potentially disadvantaging the interests of all stockholders, without paying all stockholders an appropriate control premium or providing the Company's Board sufficient time to make informed decisions in the best interest of all stockholders. In general terms, the Rights Agreement imposes significant dilution upon any person or group that acquires 25% or more of the outstanding Common Stock, including through certain derivatives agreements, without the approval of the Board (an “Acquiring Person”). The Rights Agreement is not intended to deter offers that are fair and otherwise in the best interests of the Company's stockholders, and does not prevent the Board from considering any proposal. In adopting the Rights Agreement, the Board noted, in particular, the continued accumulation of approximately 24% of shares of Talos common stock by Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial”). The Rights Agreement is similar to those adopted by other publicly traded companies and is intended to enable all Talos stockholders to realize the long-term value of their investment and protect Talos from any future efforts to obtain control of the Company that are inconsistent with the best interests of its stockholders. See Part I, Item 1. “Financial Statements — Note 15 —Subsequent Events” for more information on the Rights Agreement and Item 1. “Financial Statements — Note 12 —Related Party Transactions” for additional information on Control Empresarial.
Previous report
The Rights Agreement is filed as Exhibit 4.11 to this Quarterly Report. This description of the Rights Agreement in this Quarterly Report does not purport to be complete and is qualified in its entirety by reference to Exhibit 4.11.
Previous report
Chief Executive Officer Transition — On August 29, 2024, Timothy S. Duncan departed his role as President and Chief Executive Officer of the Company, effective immediately. The Company also announced that Joseph A. Mills will serve as Interim Chief Executive Officer and President, effective as of August 29, 2024. The Board is working to identify a permanent Chief Executive Officer and has retained an executive search firm to assist in the process.
Previous report
During the second quarter of 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 1.6 MBoepd for the nine months ended September 30, 2024 based on production rates prior to the shut-in.
Previous report
The U.S. Energy Information Administration (“EIA”) published its October 2024 Short-Term Energy Outlook on October 8, 2024. Oil prices fell in September as concerns over global oil demand growth outweighed declines in oil inventories and a decision made by OPEC Plus to delay production increases until December 2024. However, oil prices rose in early October after recent military actions involving Israel, Lebanon, and Iran. The potential for further escalation creates significant uncertainty, increasing the possibility for supply disruptions and price volatility. The EIA expects the NYMEX WTI spot prices to average $71.97 per barrel in the fourth quarter of 2024 and $73.13 per barrel in 2025. The EIA expects the Henry Hub price to continue rising to around $2.80 per MMBtu in the fourth quarter of 2024 and to further increase to around $3.10 per MMBtu on average in 2025 as liquefied natural gas exports, a component of total natural gas demand, increase with the addition of capacity.
Previous report
The U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. Sustained levels of high inflation generally cause the U.S. Federal Reserve (the “Fed”) and other central banks to increase interest rates. The Fed raised its benchmark interest rate 11 times between March 2022 and July 2023 to curb inflation. The Fed wants inflation to return to its 2% goal over time and it is still high in absolute terms. The Fed has lowered its benchmark interest rate twice since September 2024 by an aggregate 75 basis points to a new range of 4.50%-4.75% from its 23-year high of 5.25% to 5.50%. Future changes to the benchmark interest rate remain uncertain.
Previous report
BOEM Bonding Rule —On April 15, 2024, BOEM issued its final rule, entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations,” which significantly increases the amount of new supplemental financial assurance required from lessees and grant holders conducting operations on the U.S. federal outer continental shelf (“OCS”). The final rule replaces the prior five-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead requires lessees to meet one of two criteria based on: (1) the credit rating of the lessee or (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. As a result of the new rule, BOEM will no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance will be required by current lessees and grant holders. The final rule, which became effective on June 29, 2024, adopts a three-year phased compliance period for full payment of a supplemental financial assurance demand. Per BOEM’s June 28, 2024 news release, BOEM anticipates it will take up to 24 months to complete the processing of financial assurance demands for execution. The final rule was challenged in the U.S. District Court for the Western District of Louisiana by multiple oil and gas industry groups and the States of Mississippi, Louisiana, and Texas on June 17, 2024. Although implementation of the rule is not currently stayed, the outcome of these challenges remain uncertain.
Previous report
As discussed in our 2023 Annual Report, including under Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry,” we may be unable to provide the financial assurances in the amounts and under the time periods required by the new rule. If we are unable to comply with these requirements, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including assessing civil penalties, commencing proceedings to suspend our production and other operations or canceling our affected federal offshore leases. In addition, as a result of continuing adverse developments in restructurings and bankruptcies of companies operating in the OCS, a number of bonding companies have left the offshore surety market over the last twelve months, which has materially reduced the availability of surety bonds for projects in the OCS. As a result, there may not be sufficient surety bonds capacity available for companies in the OCS to comply with the new financial assurances rule. Our inability to obtain adequate supplemental financial assurance in order to comply with BOEM’s final rule, including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our financial condition, cash flows, business, properties, liquidity and results of operations.
Previous report
Deepwater Operations —We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.
Previous report
Oil Spill Response Plan —We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the BSEE biennially, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.
Previous report
Five-Year Offshore Oil and Gas Leasing Program Update —Under the Outer Continental Shelf Lands Act (“OCSLA”), as amended, BOEM prepares and maintains forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the OCS. As previously disclosed in our 2023 Annual Report, we were the high bidder on thirteen offshore Gulf of Mexico blocks related to Lease Sale 261 held by BOEM and awarded four leases. Subsequently, we were awarded leases on our remaining high-bid blocks. Additionally, QuarterNorth was the high bidder on four offshore blocks related to Lease Sale 261 and they were also awarded leases on all of their high-bid blocks.
Previous report
The 2024-2029 national program began on July 1, 2024, and will continue through June 30, 2029. It is possible, however, that this program could be delayed by opposing lawsuits that were filed on February 12, 2024 by the American Petroleum Institute and Earthjustice representing multiple environmental groups, both of which are challenging BOEM’s actions. Despite these challenges, on April 1, 2024, BOEM announced the availability of the Area Identification for proposed Gulf of Mexico lease sales 262, 263 and 264 pursuant to the 2024-2029 national program. Lease Sale 262 is tentatively scheduled for 2025.
Previous report
Endangered Species —On August 19, 2024, a U.S. District Court in Maryland ruled in favor of a coalition of environmental groups that, in 2020, filed suit against the National Marine Fisheries Service (“NMFS”), claiming that NMFS’s 2020 Biological Opinion, along with its associated reasonable and prudent alternative and incidental take statement, covering all activities associated with the OCS oil and gas program in the Gulf of Mexico, did not comply with the Endangered Species Act (“ESA”) or the Administrative Procedure Act. In her ruling, the Maryland District Court Judge vacated the 2020 Biological Opinion effective December 20, 2024. On September 16, 2024, NMFS filed a motion to alter or amend the Maryland District Court’s August 19, 2024 judgment and order requiring vacatur of the 2020 Biological Opinion by December 20, 2024, stating that it is unable to issue a new Biological Opinion by that date. On October 21, 2024, the Maryland District Court extended the vacatur deadline until May 21, 2025, which NMFS believes provides sufficient time to prepare and issue a new Biological Opinion. Further, industry groups appealed the Maryland District Court’s decision to the U.S. Court of Appeals for the Fourth Circuit. The outcome of that challenge remains uncertain. Although NMFS intends to prepare a new Biological Opinion in advance of the May 2025 deadline, any revised Biological Opinion that NMFS issues may face similar scrutiny as the 2020 Biological Opinion and may also be subject to legal challenge. Without an active OCS Gulf of Mexico oil and gas program Biological Opinion in place, all permits, plans and government actions would likely require individual project-specific ESA consultations between BOEM or BSEE (as applicable) and NMFS, which due to significant delay could adversely impact our ability to obtain plans, permits and government approvals required for our Gulf of Mexico operations until a new Biological Opinion is issued by NMFS. See Part I, Item 1A. “Risk Factors — Risks Related to Our Business and the Oil and Natural Gas Industry — Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine life and endangered and threatened species” of our 2023 Annual Report for additional information regarding the potential risks of these regulatory developments to our operations.
Previous report
Nine Months Ended September 30, 2024 and 2023 Volumetric Analysis —Production volumes increased by 24.7 MBoepd to 90.5 MBoepd. The increase was primarily due to 20.6 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 2.1 MBoepd from the EnVen Acquisition that closed mid-first quarter of 2023. Additionally, production volumes increased 10.0 MBoepd production from the Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023. These increases were partially offset by decreases of 5.0 MBoepd due to well performance and natural production declines as well as 1.4 MBoepd due to disruptions from weather events in the U.S. Gulf of Mexico. Additionally, we deferred approximately 1.6 MBoepd of production resulting from third party downtime associated with the HP-I dry-dock in our Phoenix Field.
Previous report
Three Months Ended September 30, 2024 and 2023 — Lease operating expense for the three months ended September 30, 2024 increased by approximately $59.8 million, or 58%. This increase was primarily related to lease operating expenses of $63.8 million incurred in connection with assets acquired in the QuarterNorth Acquisition. Included in the increase during the three months ended September 30, 2024 is $33.1 million in facility and well workover expenses at the Gunflint Field.
Previous report
Nine Months Ended September 30, 2024 and 2023 — Lease operating expense for the nine months ended September 30, 2024 increased by approximately $169.8 million, or 59%. This increase was related to lease operating expenses of $116.7 million incurred in connection with assets acquired in the QuarterNorth Acquisition as well as a $10.1 million increase in lease operating expenses due to the EnVen Acquisition that closed in mid-first quarter 2023.
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The increase in lease operating expense related to the QuarterNorth Acquisition included a $33.4 million increase in facility and well workover expenses at the Gunflint Field.
Previous report
Additionally, there was a $54.2 million increase in facility and workover expense primarily related to the HP-I and major well workover expenses at the Phoenix Field and the Garden Banks 506 Field associated with our historical operations. The increase attributable to our historical operations was partially offset by $14.7 million in lower marine and helicopter transportation costs, commodity transportation costs and contract labor.
Previous report
Three Months Ended September 30, 2024 and 2023 — Depreciation, depletion and amortization expense for the three months ended September 30, 2024 increased by approximately $110.9 million, or 68% due to increased production volumes, which are described above. Additionally, the depletion rate increased by $3.11 per Boe, or 11%, on our proved oil and natural gas properties.
Previous report
Nine Months Ended September 30, 2024 and 2023 —General and administrative expense for the nine months ended September 30, 2024 increased by approximately $38.7 million, or 32%. This increase was primarily related to the Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $45.2 million or $2.84 per Boe. Unallocated corporate reflects an increase in transaction costs and severance costs of $8.4 million related to the TLCS Divestiture. Additionally, there was an increase in contractor and payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. These increases were partially offset by a decrease in the Upstream Segment transaction costs for the EnVen Acquisition of $39.7 million or $2.21 per Boe. Additionally, the CCS Segment expenses decreased by $6.3 million due to the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.
Previous report
Other Operating (Income) Expense — During the three months ended September 30, 2024, other operating (income) expense primarily reflects an incremental $13.5 million gain on the TLCS Divestiture due to the recognition of contingent consideration as well as a $7.0 million increase in fair value of a service credit acquired via the QuarterNorth Acquisition. During the three months ended September 30, 2023, we recognized a gain of $66.2 million related to the deconsolidation of Talos Mexico (as defined below) partially offset by $8.0 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency.
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Nine Months Ended September 30, 2024 and 2023 —
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Accretion Expense —During the nine months ended September 30, 2024, we recorded $87.1 million of accretion expense compared to $63.4 million during the nine months ended September 30, 2023. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of both the EnVen Acquisition and QuarterNorth Acquisition and upward revisions of our asset retirement obligations. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”
Previous report
Other Operating (Income) Expense — During the nine months ended September 30, 2024, we recognized a gain of $100.4 million on the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion. During the nine months ended September 30, 2023, we recognized a gain of $66.2 million related to the deconsolidation of Talos Mexico partially offset by $9.5 million of estimated decommissioning obligations primarily as a result of unrelated third parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency.
Previous report
Our liquidity could be impacted in the future by financial assurance requirements. See “Known Trends and Uncertainties —BOEM Bonding Rule.”
Previous report
Common Stock Repurchase Program — Our Board authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. In July 2024, our Board authorized an increase of $150.0 million to the previously approved limit increasing the amount remaining under the authorized plan to $159.7 million. All repurchased shares are held in treasury. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022 applies to our share repurchase program. We do not currently anticipate incurring any excise tax in 2024 based on the fair market value of the common stock issued during 2024.
Previous report
During the nine months ended September 30, 2024, we repurchased approximately 4.0 million shares for $45.1 million. As of September 30, 2024, there is $157.5 million remaining under the authorized program. See Part II, Item 2. “Unregistered Sales of Equity Securities and Use of Proceeds” for additional information on repurchases made during the three months ended September 30, 2024.
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Operating Activities — Net cash provided by operating activities increased $270.4 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023 primarily attributable to an increase from revenues offset with an increase in lease operating expense of $245.7 million.
Previous report
Redemption of the 12.00% Second-Priority Senior Secured Notes — due January 2026 — On February 7, 2024, we redeemed $638.5 million aggregate principal amount of the 12.00% Notes using the proceeds from the issuance of the New Senior Notes. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.
Previous report
Redemption of the 11.75% Senior Secured Second Lien Notes — due April 2026 —On February 7, 2024, we redeemed $227.5 million aggregate principal amount of the 11.75% Notes using the proceeds from the issuance of the New Senior Notes. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.
Previous report
The following table and discussion summarize our material cash requirements from known contractual obligations as of September 30, 2024 (in thousands):
Previous report
Includes vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs.
Previous report
Lease agreement for the HP-I floating production facility we utilize to produce the Phoenix Field.
Previous report
Includes firm transportation commitments as further discussed under Part I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies” and deferred payments related to our acquisition of working interests in the Monument oil discovery as further discussed under Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.”
Previous report
This table does not include our estimated liability for dismantlement, abandonment and restoration costs of oil and natural gas properties with a carrying value of $1,189.9 million as of September 30, 2024. For additional information regarding these liabilities, please see Part I, Item 1. “Financial Statements — Note 8 —Asset Retirement Obligations.” Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part I, Item 1. “Financial Statements — Note 13 —Commitments and Contingencies.”
Reworded paragraphs (38)
Previous wording
We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) and offshore Mexico. We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world.
Current wording
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.
Previous wording
We have historically focused our oil and gas exploration and production operations in the U.S. Gulf of Mexico 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 a large and expanding 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.
Current wording
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.
Previous wording
The following significant developments have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2024, with the SEC on August 8, 2024.
Current wording
The following significant developments have occurred since the filing of our 2024 Annual Report.
Previous wording
QuarterNorth Acquisition —On March 4, 2024, we acquired QuarterNorth Energy Inc. (“QuarterNorth”), a private operator in the Deepwater U.S. Gulf of Mexico (the “QuarterNorth Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.
Current wording
QuarterNorth Acquisition —On March 4, 2024, we acquired QuarterNorth Energy Inc. (“QuarterNorth”), a private operator in the Deepwater U.S. Gulf of America (the “QuarterNorth Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.
Previous wording
Hurricanes, Tropical Storms and Loop Currents —Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes, tropical storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of future production and revenues and increased lease operating expenses for evacuations and repairs.
Current wording
• Hurricanes, Tropical Storms, Winter Storms and Loop Currents
Previous wording
See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2023 Annual Report for a detailed discussion of known trends and uncertainties. The following carries forward or provides an update to known trends and uncertainties discussed in our 2023 Annual Report.
Current wording
The following provides an update to known trends and uncertainties discussed in our 2024 Annual Report.
Previous wording
During the period January 1, 2024 through September 30, 2024, the daily spot prices for NYMEX WTI crude oil ranged from a high of $87.69 per Bbl to a low of $66.73 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $13.20 per MMBtu to a low of $1.25 per MMBtu. The price the Company realizes on natural gas sales is based on the MMBtu content of such natural gas. We convert MMBtu sales volumes to Mcf volumes for reporting purposes using MMBtu per Mcf factors per third party natural gas processing plant statements. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices we realize for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Financial Statements — Note 5 —Financial Instruments” for additional information regarding our commodity derivative positions as of September 30, 2024.
Current wording
During the period January 1, 2025 through March 31, 2025, the daily spot prices for NYMEX WTI crude oil ranged from a high of $80.73 per Bbl to a low of $66.31 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.86 per MMBtu to a low of $2.93 per MMBtu. The price the Company realizes on natural gas sales is based on the MMBtu content of such natural gas. We convert MMBtu sales volumes to Mcf volumes for reporting purposes using MMBtu per Mcf factors per third party natural gas processing plant statements. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices we realize for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Financial Statements — Note 5 —Financial Instruments” for additional information regarding our commodity derivative positions as of March 31, 2025.
Previous wording
Inflation of Cost of Goods, Services and Personnel —Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increases, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices. Sustained levels of high inflation may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Inflation may also result in higher interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business.
Current wording
Inflation may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Inflation may also result in higher interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business.
Previous wording
Impairment of Oil and Natural Gas Properties —Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three and nine months ended September 30, 2024 and 2023, we did not recognize an impairment based on the ceiling test computations. At September 30, 2024 our ceiling test computation was based on SEC pricing of $80.66 per Bbl of oil, $2.32 per Mcf of natural gas and $19.06 per Bbl of NGLs.
Current wording
Impairment of Oil and Natural Gas Properties —Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three months ended March 31, 2025 and 2024, we did not recognize an impairment based on the ceiling test computations. At March 31, 2025 our ceiling test computation was based on SEC pricing of $74.52 per Bbl of oil, $2.78 per Mcf of natural gas and $21.19 per Bbl of NGLs.
Previous wording
If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning October 1, 2023 and ending September 1, 2024 used in the determination of the SEC pricing was 10% lower, resulting in $72.77 per Bbl of oil, $2.10 per Mcf of natural gas and $17.15 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $293.0 million.
Current wording
If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning April 1, 2024 and ending March 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $67.01 per Bbl of oil, $2.53 per Mcf of natural gas and $19.16 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $610.0 million assuming all other factors remained constant.
Previous wording
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 2023 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in SEC pricing 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.
Current wording
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.
Previous wording
Third Party Planned Downtime —Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. For example, we produce the Phoenix Field through the Helix Producer I (“HP-I”) that is operated by Helix Energy Solutions Group, Inc. (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field.
Current wording
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.
Previous wording
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
Current wording
We use a variety of financial and operational metrics to assess the performance of our operations, including:
Previous wording
The information below provides an analysis of the change in our oil, natural gas and NGL revenues in our Upstream Segment due to changes in sales prices and production volumes (in thousands):
Current wording
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):
Previous wording
Three Months Ended September 30, 2024 and 2023 Volumetric Analysis —Production volumes increased by 32.8 MBoepd to 96.5 MBoepd. The increase was primarily due to 26.2 MBoepd of production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, there was 9.5 MBoepd production from our operated Venice and Lime Rock wells, which tie back to our Ram Powell facility, which commenced initial production late in the fourth quarter of 2023 as well as 2.9 MBoepd production from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. These increases were partially offset by a decrease of 4.2 MBoepd of production due to disruptions from weather events in the U.S. Gulf of Mexico. Additionally, there was a decrease of approximately 2.7 MBoepd due to well performance and natural production declines.
Current wording
Three Months Ended March 31, 2025 and 2024 Volumetric Analysis — Production volumes increased by 21.3 MBoepd to 100.9 MBoepd. The increase was primarily due to 22.8 MBoepd of production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 6.8 MBoepd of production from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. Additionally, there was 2.0 MBoepd in deferred production resulting from third party infrastructure downtime primarily from our Lobster Field in the corresponding period in 2024. These increases were partially offset by a decrease of approximately 8.3 MBoepd due to well performance and natural production declines.
Previous wording
Nine Months Ended September 30, 2024 and 2023 — Depreciation, depletion and amortization expense for the nine months ended September 30, 2024 increased by approximately $268.5 million, or 56%. This was due to an increase of $3.54 per Boe, or 13%, in the depletion rate on our proved oil and natural gas properties due to our amortization base increasing disproportionately to the increase in our reserve base. Our amortization base increased primarily due to the proved properties acquired as part of the QuarterNorth Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.”
Current wording
Three Months Ended March 31, 2025 and 2024 — Depreciation, depletion and amortization expense for the three months ended March 31, 2025 increased by approximately $65.1 million, or 30%. This increase was primarily driven by the increased production volumes of 21.3 MBoepd discussed above and to a lesser extent an increase of $1.14 per Boe, or 4% in the depletion rate on our proved oil and natural gas properties. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures” for further discussion.
Previous wording
Three Months Ended September 30, 2024 and 2023 —General and administrative expense for the three months ended September 30, 2024 increased by approximately $17.0 million, or 68%. This increase was primarily due to an increase in contractor and payroll expenses due to an increase in employee headcount primarily related to the QuarterNorth Acquisition. Additionally, there was an increase related to Upstream Segment transaction costs, severance costs and additional general and administrative expenses related to the QuarterNorth Acquisition of $3.1 million or $0.35 per Boe as well as an increase in non-cash equity-based compensation of $2.9 million. These increases were partially offset by a decrease in the CCS Segment expenses of $2.5 million due to the TLCS Divestiture. Additionally, Upstream Segment transaction costs for the EnVen Acquisition decreased $1.5 million or $0.26 per Boe. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.
Current wording
Three Months Ended March 31, 2025 and 2024 —General and administrative expense for the three months ended March 31, 2025 decreased by approximately $35.2 million, or 50%. This decrease was primarily driven by Upstream Segment transaction costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $30.7 million or $3.38 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.8 million due to the divestiture of our CCS business. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for further discussion.
Previous wording
Accretion Expense —During the three months ended September 30, 2024, we recorded $29.4 million of accretion expense compared to $21.3 million during the three months ended September 30, 2023. The change is primarily the result of a $4.6 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”
Current wording
Accretion Expense —During the three months ended March 31, 2025, we recorded $30.9 million of accretion expense compared to $26.9 million during the three months ended March 31, 2024. The change is primarily the result of a $3.1 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition in early March 2024. See Part I, Item 1. “Financial Statements—Note 2—Acquisitions and Divestitures.”
Previous wording
From January 1, 2024 through March 18, 2024, we had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”), of which the Company’s only reportable segment was the Upstream Segment. On March 18, 2024, we entered into a definitive agreement relating to and subsequently completed the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). Subsequent to the TLCS Divestiture and our sale of the entire CCS business, we had one operating segment. See Part I, Item 1. “Financial Statements — Note 14 —Segment Information” for additional information on our business segments and Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information on the TLCS Divestiture.
Current wording
Other Operating (Income) Expense — During the three months ended March 31, 2024, we recognized a gain of $86.9 million due to the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.”
Previous wording
Interest Expense —During the nine months ended September 30, 2024, we recorded $146.1 million of interest expense compared to $128.9 million during the nine months ended September 30, 2023. The change is primarily the result of an increase in debt outstanding offset by a lower rate of interest on these instruments. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information. Additionally, there was an increase of $4.9 million of fees associated with the unutilized bridge loan. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.
Current wording
Interest Expense — During the three months ended March 31, 2025, we recorded $40.9 million of interest expense compared to $50.8 million during the three months ended March 31, 2024. The change is primarily due to a $5.1 million decrease in interest expense related to the Bank Credit Facility as a result of lower borrowings compared to the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information. Additionally, there was a decrease of $4.9 million of fees associated with an unutilized bridge loan during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.
Previous wording
Price Risk Management Activities — The income of $126.3 million for the three months ended September 30, 2024 consists of $120.2 million in non-cash gains from the increase in the fair value of our open derivative contracts and $6.1 million in cash settlement gains. The expense of $98.8 million for the three months ended September 30, 2023 consists of $92.5 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $6.3 million in cash settlement losses.
Current wording
Price Risk Management Activities — The expense of $15.9 million for the three months ended March 31, 2025 consists of $21.0 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $5.2 million in cash settlement gains. The expense of $87.1 million for the three months ended March 31, 2024 consists of $83.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $3.5 million in cash settlement losses.
Previous wording
Equity Method Investment (Income) Expense — During the nine months ended September 30, 2024, we recorded equity losses of $9.1 million. During the nine months ended September 30, 2023, we recorded an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend CCS LLC (“Bayou Bend”) by Chevron U.S.A. Inc. (“Chevron”) offset by equity losses of $5.6 million.
Current wording
Equity Method Investment (Income) Expense — During the three months ended March 31, 2024, we recorded equity losses of $8.1 million primarily related to our CCS Segment.
Previous wording
Other (Income) Expense— During the nine months ended September 30, 2024, we recorded a $60.3 million loss on extinguishment of debt in conjunction with the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”). See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.
Current wording
Other (Income) Expense — During the three months ended March 31, 2025, we had $3.9 million of other income compared to $55.9 million in other expense for the three months ended March 31, 2024. The change is primarily a result of a $60.3 million loss on extinguishment of debt from the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) during the three months ended March 31, 2024.
Previous wording
Income Tax (Benefit) Expense — During the three months ended September 30, 2024, we recorded $18.1 million of income tax expense compared to $15.9 million of income tax benefit during the three months ended September 30, 2023. The income tax expense recorded during the three months ended September 30, 2024 is primarily due to current year activity offset by the impact from permanent differences. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”
Current wording
Income Tax (Benefit) Expense — During the three months ended March 31, 2025, we recorded $0.1 million of income tax benefit compared to $21.6 million of income tax benefit during the three months ended March 31, 2024. The income tax benefit recorded during the three months ended March 31, 2025 is primarily due to current year activity offset by the impact from permanent differences. See additional information in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”
Previous wording
EBITDA — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense.
Current wording
EBITDA — Net income (loss) plus interest expense, income tax benefit (expense), depreciation, depletion and amortization, and accretion expense.
Previous wording
For the three months ended September 30, 2024, transaction expenses include $4.7 million in severance expense related to the departure of the Company’s former President and Chief Executive Officer as discussed in Part I, Item 1. “Financial Statements — Note 9 —Employee Benefits Plans and Share-Based Compensation.” For the nine months ended September 30, 2024, transaction expenses include $38.8 million in costs related to the QuarterNorth Acquisition, inclusive of $22.3 million in severance expense, and $8.4 million in costs related to the TLCS Divestiture, inclusive of a net $2.9 million in severance expense. For the three and nine months ended September 30, 2023, transaction expenses included $1.5 million and $39.4 million, respectively, in costs related to the EnVen Acquisition, inclusive of $0.9 million and $24.9 million, respectively, in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” and “Note 9 —Employee Benefits Plans and Share-Based Compensation.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three and nine months ended September 30, 2024, it includes a gain of $13.5 million and $100.4 million related to the TLCS Divestiture, respectively. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.” Additionally, for the three and nine months ended September 30, 2024, it includes a gain of $7.0 million and $9.5 million, respectively, related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the three and nine months ended September 30, 2023, the amount includes a $66.2 million gain related to the deconsolidation of Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”). For the nine months ended September 30, 2023, the amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million.
Current wording
For the three months ended March 31, 2024, transaction expenses included $28.1 million in costs related to the QuarterNorth Acquisition, inclusive of $14.2 million in severance expense and $9.8 million in costs related to the TLCS Divestiture, inclusive of $3.7 million in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.” Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, the amount included a gain of $86.9 million related to the TLCS Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures.”
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 borrowings under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed made it more expensive to borrow money. As of September 30, 2024, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $842.9 million.
Current wording
Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility (as defined herein). Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases and for general corporate purposes. The cost of 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
We fund our development and exploration 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 equity issuances. We 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.
Current wording
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.
Previous wording
Capital Expenditures —The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2024 (in thousands):
Current wording
Capital Expenditures —The following is a table of our capital expenditures, excluding acquisitions, for the three months ended March 31, 2025 (in thousands):
Previous wording
Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remaining portion of our 2024 Upstream capital spending program of $510.0 million to $530.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $110.0 million. However, our ability to (i) generate sufficient cash flows from operations, (ii) obtain future borrowings under the Bank Credit Facility, and (iii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, many of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g., by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to take additional future actions on an opportunistic basis. To address further changes in the financial or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.
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 $500.0 million to $540.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $120.0 million. However, our ability to (i) generate sufficient cash flows from operations, (ii) obtain future borrowings under the Bank Credit Facility, and (iii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on various operating and economic conditions, many of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g., by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to take additional future actions on an opportunistic basis. To address further changes in the financial or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.
Previous wording
Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.
Current wording
Repurchases 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.
Previous wording
Investing Activities — Net cash used in investing activities increased $776.2 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023 primarily due to cash paid for acquisitions of $936.2 million, net of cash acquired, of which $916.0 million related to the QuarterNorth Acquisition. Cash proceeds of $142.0 million was received from the TLCS Divestiture during the nine months ended September 30, 2024 compared to $66.2 million of net proceeds from the sale of property and equipment during the corresponding period in 2023. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information on the QuarterNorth Acquisition and TLCS Divestiture. Additionally, capital expenditures decreased $83.3 million.
Current wording
Investing Activities — Cash used in investing activities changed $794.3 million in the three months ended March 31, 2025 compared to the corresponding period in 2024. This is primarily due to $916.0 million in cash paid for acquisitions, net of cash acquired, related to the QuarterNorth Acquisition offset by cash proceeds of $142.0 million received from the TLCS Divestiture during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for additional information on the QuarterNorth Acquisition and TLCS Divestiture. Additionally, capital expenditures decreased $17.1 million and contributions to equity method investees decreased of $17.5 million.
Previous wording
Financing Activities —Cash flow from financing activities changed $449.4 million in the nine months ended September 30, 2024 compared to the corresponding period in 2023. During the nine months ended September 30, 2024, the issuance of the New Senior Notes in February 2024 generated $1,220.1 million after deferred financing costs. The net proceeds from the New Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for additional information. Additionally, on January 17, 2024, we entered into anunderwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. Furthermore, Bank Credit Facilitynet repayments of $75.0 million were made during the nine months ended September 30, 2024 due to a management goal to maintain or reduce our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. We had net borrowings from the Bank Credit Facility of $215.0 million during the corresponding period in 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures.
Current wording
Financing Activities —Cash flows related to financing activities changed $859.0 million in the three months ended March 31, 2025 compared to the corresponding period in 2024. During the three months ended March 31, 2025, we cash settled $17.3 million of our common stock repurchased through our share repurchase program. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. During the three months ended March 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,224.5 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition as discussed in our 2024 Annual Report. Additionally, on January 17, 2024, we entered into anunderwritten public offering of 34.5 million shares of our common stock, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. Furthermore, the Bank Credit Facility had net borrowings of $125.0 million during the corresponding period in 2024.
Previous wording
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 are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.
Current wording
9.000% Second-Priority Senior Secured Notes — due February 2029 —The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.
Previous wording
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 “New 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 are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.
Current wording
9.375% Second-Priority Senior Secured Notes — due February 2031 —The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for more information.
Previous wording
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.
Current wording
We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements. There have been no material changes to our contractual obligations since those reported in our 2024 Annual Report except for purchase obligations increased from $40.7 million to $85.1 million through 2026 primarily due to increased committed purchase orders to execute planned future drilling activities.
Previous wording
Performance Obligations —As of September 30, 2024, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $42.7 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition. See Part I, Item 1. “Financial Statements — Note 7 —Debt” for further information on the Bank Credit Facility.
Current wording
Performance Obligations —As of March 31, 2025, we had secured performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $42.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2024 Annual Report subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements” and “— Known Trends and Uncertainties — Financial Assurance Market Outlook” for additional information on BOEM’s supplemental bonding requirements and the potential lack of surety bond capacity to comply with BOEM’s financial assurance requirements, which could have a material adverse effect on our business, properties, results of operations and financial condition.
Previous wording
No accounting standards were issued during the quarterly period ended September 30, 2024 that were material to us.
Current wording
No accounting standards were issued during the quarterly period ended March 31, 2025 that were material to us. In addition, information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part I, Item 1. “Financial Statements— Note 1— Organization, Nature of Business and Basis of Presentation.”
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
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.
Rearranged previous paragraphs (4)
Previous report — wording carried elsewhere
EnVen Acquisition —On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 —Acquisitions and Divestitures” for more information.
Previous report — wording carried elsewhere
Price Risk Management Activities —The income of $41.5 million for the nine months ended September 30, 2024 consists of $56.5 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $14.9 million in cash settlement losses. The expense of $13.7 million for the nine months ended September 30, 2023 consists of $3.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $10.5 million in cash settlement losses.
Previous report — wording carried elsewhere
Income Tax (Benefit) Expense —During the nine months ended September 30, 2024, we recorded $4.4 million of income tax benefit compared to $55.5 million of income tax benefit during the nine months ended September 30, 2023. The income tax benefit is primarily due to current year activity offset by the impact from permanent differences and a non-cash income tax benefit recognized in the Company’s state deferred tax liability. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 —Income Taxes.”
Previous report — wording carried elsewhere
Includes committed purchase orders to execute planned future oil and natural gas operational activities.