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What changed in W&T OFFSHORE INC's 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of W&T OFFSHORE INC's 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+338 added−340 removedSource: 10-K (2026-03-16) vs 10-K (2025-03-04)

Top changes in W&T OFFSHORE INC's 2025 10-K

338 paragraphs added · 340 removed · 232 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

43 edited+31 added−36 removed71 unchanged
Biggest changeAdditionally, numerous proposals have been made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHG as well as to restrict or eliminate such future emissions. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.
Biggest changeThese efforts have included consideration of cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. Compliance with these rules or others could result in increased compliance costs on our operations.
Our producing fields are located in federal and state waters in the Gulf of America in water depths ranging from less than 10 feet up to 7,300 feet. The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, with higher initial production rates relative to other domestic reservoirs.
Our producing fields are located in federal and state waters in the Gulf of America in water depths ranging from less than 10 feet to up to 7,300 feet. The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, with higher initial production rates relative to other domestic reservoirs.
We intend to execute the following elements of our business strategy in order to achieve our strategic goals: ● Exploit existing and acquired properties to add additional reserves and production; ● Explore for reserves on our extensive acreage holdings and in other areas of the Gulf of America; ● Acquire reserves with substantial upside potential and additional leasehold acreage complementary to our existing acreage position at attractive prices; ● Continue to manage our balance sheet in a prudent manner and continuing our track record of financial flexibility in any commodity price environment; and ● Carry out our business strategy in a safe and socially responsible manner.
We intend to execute the following elements of our business strategy in order to achieve our strategic goals: ● Exploit existing and acquired properties to add additional reserves and production; ● Explore for reserves on our extensive acreage holdings and in other areas of the Gulf of America; ● Acquire reserves with substantial upside potential and additional leasehold acreage complementary to our existing acreage position at attractive prices; ● Continue to manage our balance sheet in a prudent manner and continue our track record of financial flexibility in any commodity price environment; and ● Carry out our business strategy in a safe and socially responsible manner.
The federal environmental laws and regulations applicable to us and our operations include, among others, the following: ● The Resource Conservation and Recovery Act, as amended, regulates the generation, transportation, storage, treatment and disposal of non-hazardous and hazardous wastes and can require cleanup of hazardous waste disposal sites; ● The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, (“CERCLA”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment; ● The Clean Air Act, as amended (the “CAA”), and comparable state and local requirements restrict the emission of air pollutants from many sources through the imposition of air emission standards, construction and operating permitting programs and other compliance requirements; ● The Clean Water Act, as amended, and analogous state laws, prohibit any discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental agencies; 4 Table of Contents ● The Oil Pollution Act of 1990, as amended (the “OPA”), holds owners and operators of offshore oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing oil discharged into waters of the United States, including the OCS or adjoining shorelines, and for certain damages from such spills; ● The Endangered Species Act, as amended, restricts activities that may affect federally identified endangered and threatened species or their habitats; ● The Migratory Bird Treaty Act, as amended, implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds; and ● The National Environmental Policy Act, as amended, requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands.
The federal environmental laws and regulations applicable to us and our operations include, among others, the following: ● The Resource Conservation and Recovery Act, as amended, regulates the generation, transportation, storage, treatment and disposal of non-hazardous and hazardous wastes and can require cleanup of hazardous waste disposal sites; ● The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, (“CERCLA”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment; ● The Clean Air Act, as amended (the “CAA”), and comparable state and local requirements restrict the emission of air pollutants from many sources through the imposition of air emission standards, construction and operating permitting programs and other compliance requirements; ● The Clean Water Act, as amended, and analogous state laws, prohibit any discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental agencies; ● The Oil Pollution Act of 1990, as amended (the “OPA”), holds owners and operators of offshore oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing oil discharged into waters of the United States, including the OCS or adjoining shorelines, and for certain damages from such spills; ● The Endangered Species Act, as amended, restricts activities that may affect federally identified endangered and threatened species or their habitats; ● The Migratory Bird Treaty Act, as amended, implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds; and ● The National Environmental Policy Act, as amended, requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands.
The Gulf of America is an area where we have developed significant technical expertise and where high production rates associated with hydrocarbon deposits have historically provided us the best opportunity to achieve high rates of return on our invested capital. ● Maintain high-quality conventional asset base with low decline.
The Gulf of America is an area where we have developed significant technical expertise and where high production rates associated with hydrocarbon deposits have historically provided us the best opportunity to achieve high rates of return on our invested capital. ● Maintain and optimize high-quality conventional asset base with low decline.
In October 2023, the Federal Reserve, Office of the Comptroller of the Currency and the Federal Deposit Insurance Corporation (the “FDIC”) released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change.
In addition, in October 2023, the Federal Reserve, Office of the Comptroller of the Currency and the Federal Deposit Insurance Corporation (the “FDIC”) released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change.
Our general and excess liability policies provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination.
Our general and excess liability policies currently provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination.
The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, 7 Table of Contents reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements.
The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements.
We believe these solutions help the overall health and wellness of our employees and help us successfully manage healthcare and prescription drug costs for our employee population. Website Access to Company Reports We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments to those reports with the SEC.
We believe these solutions help the overall health and wellness of our employees and help us successfully manage healthcare and prescription drug costs for our employee population. 10 Table of Contents Website Access to Company Reports We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments to those reports with the SEC.
We are not currently a defendant in any of these lawsuits but could be named in 8 Table of Contents actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. Additionally, our access to capital may be impacted by climate change policies.
We are not currently a defendant in any of these lawsuits but could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition. Additionally, our access to capital may be impacted by climate change policies.
Most jurisdictions in which we operate also regulate one of more of the following: 5 Table of Contents ● the location of wells; ● the method of drilling and casing wells; ● the plugging and abandonment of wells and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines; and ● the produced water and disposal of wastewater, drilling fluids and other liquids and solids utilized or produced in the drilling and extraction process.
Most jurisdictions in which we operate also regulate one of more of the following: ● the location of wells; ● the method of drilling and casing wells; ● the plugging and abandonment of wells and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines; and ● the produced water and disposal of wastewater, drilling fluids and other liquids and solids utilized or produced in the drilling and extraction process.
This Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., 5718 Westheimer Road, Suite 700, Houston, Texas 77057 or by calling (713) 297-8024. Information on our website is not a part of this Form 10-K. ​ 11 Table of Contents
This Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., 5718 Westheimer Road, Suite 700, Houston, Texas 77057 or by calling (713) 297-8024. Information on our website is not a part of this Form 10-K.
Other than as described above, our sales of liquids, which include oil, condensate and NGLs, are not currently regulated and are transacted at market prices. Although natural gas prices are currently unregulated, Congress has historically been active in the area of natural gas regulation.
Other than as described above, our sales of liquids, which include oil, condensate and NGLs, are not currently regulated and are transacted at market prices. 7 Table of Contents Although natural gas prices are currently unregulated, Congress has historically been active in the area of natural gas regulation.
We grow in opportunistic ways as we manage our balance sheet prudently and reinvest free cash flow. Our existing portfolio of 204 structures (150 of which we operate) provides a key advantage when evaluating and developing prospect opportunities and serves to reduce capital expenditures and maximize our returns on capital expenditures. ● Preserve ample liquidity and maintain financial flexibility.
We grow in opportunistic ways as we manage our balance sheet prudently and reinvest free cash flow. Our existing portfolio of 200 structures (142 of which we operate) provides a key advantage when evaluating and developing prospect opportunities and serves to reduce capital expenditures and maximize our returns on capital expenditures. ● Preserve ample liquidity and maintain financial flexibility.
Safety and Environmental metrics are incorporated into employee evaluations when determining compensation. 10 Table of Contents Benefits and Compensation We pride ourselves on providing an attractive compensation and benefits program that allows our employees to view working at W&T as more than where they work, but a place where they may grow and develop.
Safety and Environmental metrics are incorporated into employee evaluations when determining compensation. Benefits and Compensation We pride ourselves on providing an attractive compensation and benefits program that allows our employees to view working at W&T as more than where they work, but a place where they may grow and develop.
Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting from the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations or requirements of financial institutions.
Although the rule has been stayed, any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting from the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations or requirements of financial institutions.
We have successfully discovered and produced properties on the conventional shelf and in the deepwater across the Gulf of America. We have continually grown our footprint in the Gulf of America through acquisitions, exploration and development. As of December 31, 2024, we held working interests in 52 offshore producing fields in federal and state waters.
We have successfully discovered and produced properties on the conventional shelf and in the deepwater across the Gulf of America. We have continually grown our footprint in the Gulf of America through acquisitions, exploration and development. As of December 31, 2025, we held working interests in 49 offshore producing fields in federal and state waters.
New orders instruct agencies to roll back restrictions on offshore drilling and reconsider protections for Alaska’s Arctic National Wildlife Refuge. President Trump also issued a moratorium on new wind power projects on federal lands, pausing new leases and permits for both onshore and offshore wind 9 Table of Contents farms.
New orders instruct agencies to roll back restrictions on offshore drilling and reconsider protections for Alaska’s Arctic National Wildlife Refuge. President Trump also issued a moratorium on new wind power projects on federal lands, pausing new leases and permits for both onshore and offshore wind farms.
The implementation of revised air emission standards could result in stricter permitting requirements, which could delay, limit or prohibit our ability to obtain such permits and result in increased compliance costs on our operations, including expenditures for pollution control equipment, the costs of which could be significant.
Although the rule has been overturned, the implementation of revised air emission standards could result in stricter permitting requirements, which could delay, limit or prohibit our ability to obtain such permits and result in increased compliance costs on our operations, including expenditures for pollution control equipment, the costs of which could be significant.
With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering one of our higher valued properties, and $150.0 million for all other properties subject to four region retentions ranging from $2.5 million to $15.0 million on the conventional shelf properties and $10.0 million on the deepwater properties.
With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering one of our higher valued properties, and $150.0 million for all other properties subject to four regional retentions ranging from $1.0 million to $15.0 million on the conventional shelf properties and $7.5 million on the deepwater properties.
Financial Information We operate our business as a single segment. See Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for our financial information. Human Capital Resources As of December 31, 2024, we had approximately 400 employees who conduct our business in Texas, Alabama, Louisiana and the Gulf of America.
Financial Information We operate our business as a single segment. See Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for our financial information. 9 Table of Contents Human Capital Resources As of December 31, 2025, we had approximately 370 employees who conduct our business in Texas, Alabama, Louisiana and the Gulf of America.
As discussed above, in January 2025, President Trump announced that the United States was withdrawing from the Paris Agreement. He also issued additional executive orders aimed at boosting fossil fuels and undoing Biden-era initiatives to limit GHG emissions. He declared a national energy emergency and revoked many of President Biden’s executive orders on climate change.
In January 2025, President Trump announced that the United States was withdrawing from the United Nations-sponsored “Paris Agreement.” He also issued additional executive orders aimed at boosting fossil fuels and undoing Biden-era initiatives to limit GHG emissions. He declared a national energy emergency and revoked many of President Biden’s executive orders on climate change.
Our operations on federal oil and natural gas leases in the OCS waters of the Gulf of America are subject to regulation by the BSEE, the BOEM and the ONRR, all of which are agencies of the U.S. Department of the Interior (the “DOI”).
Our operations on federal oil and natural gas leases in the OCS waters of the Gulf of America are subject to regulation by the BSEE, the BOEM and the ONRR, all of which are agencies of the DOI.
Our 2024 total recordable incident rate for employees was 0.00, which is far below the industry average for the Gulf of America from 2023 of 0.51.
Our 2025 total recordable incident rate for employees was 0.24, which is far below the industry average for the Gulf of America from 2024 of 0.58.
The IRA also imposes the first ever federal fee on the GHG emissions through a methane emissions charge. Under this rule, finalized in November 2024, the methane emissions charge for 2024 was established at $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026.
The Inflation Reduction Act of 2022 (the “IRA”) imposed the first ever federal fee on GHG emissions through a methane emissions charge. Under this rule, the methane emissions charge for 2024 was established at $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026.
Compliance with these rules or others could result in increased compliance costs on our operations. In March 2024, the EPA published its final rule establishing more stringent methane rules for new, modified, and reconstructed facilities, known as Quad Ob, as well as standards for existing sources for the first time ever, known as Quad Qc.
In March 2024, the EPA published its final rule establishing more stringent methane rules for new, modified, and reconstructed facilities, known as Quad Ob, as well as standards for existing sources for the first time ever, known as Quad Qc.
Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often costly to comply with, and a failure to comply may result in substantial administrative, civil and criminal penalties; the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, or development or expansion of projects; and the issuance of orders enjoining some or all of our operations in affected areas.
We believe that we are in substantial compliance with all such existing laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. 4 Table of Contents Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often costly to comply with, and a failure to comply may result in substantial administrative, civil and criminal penalties; the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, or development or expansion of projects; and the issuance of orders enjoining some or all of our operations in affected areas.
Although incident reporting practices are subject to some subjectivity and vary by operator, we have historically had below average incident rates compared to the industry average for the Gulf of America, and we strive to continue to excel at protecting our personnel. Our HSE&R group is comprised of a Vice President, Environmental, Safety and Regulatory Managers and 12 staff personnel.
Although incident reporting practices are subject to some subjectivity and vary by operator, we have historically had below average incident rates compared to the industry average for the Gulf of America, and we strive to continue to excel at protecting our personnel.
The BSEE and the BOEM work to ensure the development of energy and mineral resources on the OCS is done in a safe and environmentally and economically responsible way. The ONRR performs the offshore royalty and revenue management functions of the former Minerals Management Service.
The BSEE and the BOEM work to ensure the development of energy and mineral resources on the OCS is done in a safe and environmentally and economically responsible way.
The group works with field personnel to create and regularly review safety policies and procedures, in an effort to support continuous improvement of our SEMS. Our board of directors reviews our material safety metrics on a quarterly basis.
Our Health, Safety, Environmental and Regulatory (“HSE&R”) group is comprised of a Vice President, HSE&R and 15 staff personnel, including managers. The group works with field personnel to create and regularly review safety policies and procedures, in an effort to support continuous improvement of our SEMS. Our board of directors reviews our material safety metrics on a quarterly basis.
Other Regulation of the Oil and Natural Gas Industry The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Rules and regulations affecting the oil and natural gas industry are under consistent review for amendment or expansion, which could increase the regulatory burden and the potential sanctions for noncompliance.
Rules and regulations affecting the oil and natural gas industry are under consistent review for amendment or expansion, which could increase the regulatory burden and the potential sanctions for noncompliance.
Prior to commencement of offshore operations, lessees must obtain the BOEM’s approval for exploration, development and production plans. In addition to permits required from other agencies such as the U.S.
These leases are awarded by the BOEM based on competitive bidding and contain relatively standardized terms. Prior to commencement of offshore operations, lessees must obtain the BOEM’s approval for exploration, development and production plans. In addition to permits required from other agencies such as the U.S.
We believe that our coverage limits are sufficient and are consistent with our exposure; however, we cannot insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow. We re-evaluate the purchase of insurance, coverage limits and deductibles annually.
As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow. 3 Table of Contents We annually re-evaluate the purchase of insurance, coverage limits and deductibles.
Insurance Coverage In accordance with industry practice, we maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed.
Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which can delay production and sales of our oil and natural gas. Insurance Coverage In accordance with industry practice, we maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed.
The federal government cannot conduct offshore lease sales without the development and approval of a National Outer Continental Shelf Oil and Gas Leasing Program (the “OCS Program”). The Outer Continental Shelf Lands Act (the “OCSLA”) authorizes the Secretary of the Interior to establish a schedule of lease sales for a five-year period.
The ONRR performs the offshore royalty and revenue management functions of the former Minerals Management Service. 5 Table of Contents The federal government cannot conduct offshore lease sales without the development and approval of a National Outer Continental Shelf Oil and Gas Leasing Program (the “OCS Program”).
In April 2024, BOEM released a final rule that changes the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements.
In April 2024, BOEM released a final rule that changed the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements. Under the new rule, BOEM revised the criteria for determining whether OCS oil and natural gas lessees and grant holders are required to provide supplemental financial assurance to backstop their decommissioning obligations.
Securities and Exchange Commission (“SEC”) issued a final rule in March 2024 that established a framework for the reporting of climate risks, targets and metrics. In April 2024, less than a month after the issuance of the final rule, the SEC issued an order staying the rules in April 2024.
In April 2024, less than a month after the issuance of the final rule, the SEC issued an order staying the rules in April 2024. In March 2025, the SEC voted to end its defense of this rule, effectively withdrawing its support for the regulation.
Fines and penalties for violations of these rules can be substantial. It is likely, however, that the final rule and its requirements will be subject to legal challenges and regulatory revision, so we are unable to predict at this time the scope of any final regulatory requirements and the expected cost to comply with such requirements.
Fines and penalties for violations of these rules can be substantial. In July 2025, the EPA published its interim final rule extending certain compliance deadlines by 18 months. We are unable to predict the expected cost to comply with such requirements.
He revoked an executive order that compelled government regulators to assess the risks of climate change to the financial system and he instructed agencies to review any regulations that might “burden the development of domestic energy resources.” While no definitive actions have been taken, it is anticipated that such agency review could result in changes to major Biden administration climate policies, including EPA rules limiting emissions from coal- and natural gas-fired power plants and the methane emissions charge discussed above.
He revoked an executive order that compelled government regulators to assess the risks of climate change to the financial system and he instructed agencies to review any regulations that might “burden the development of domestic energy resources.” These executive orders and the subsequent changes to regulations have had a tangible impact on the regulatory environment as it relates to climate change.
There is no requirement under the OCSLA that mandates any sales in any locations, nor does the law prescribe any specific timing for the development of the OCS Program. These leases are awarded by the BOEM based on competitive bidding and contain relatively standardized terms.
The Outer Continental Shelf Lands Act (the “OCSLA”) authorizes the Secretary of the Interior to establish a schedule of lease sales for a five-year period. There is no requirement under the OCSLA that mandates any sales in any locations, nor does the law prescribe any specific timing for the development of the OCS Program.
The proposed OCS Program includes a maximum of three potential oil and natural gas lease sales in the Gulf of America scheduled in 2025, 2027 and 2029. In December 2024, BOEM released a draft environmental review around Lot Sale 262 which was to occur in 2025.
Earlier in 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and natural gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America.
In 2024, approximately 44% and 12% of our receipts from sales of oil, NGLs and natural gas were received from BP Products North America and Chevron-Texaco, respectively, with no other customer comprising greater than 10% of our 2024 receipts from sales of oil, NGLs and natural gas.
In 2025, BP Products North America and Shell Trading (US) Company accounted for 33% and 17%, respectively, of our revenues from sales of oil, NGLs and natural gas.
As a result, Lot Sale 262 is expected to be delayed until sometime in 2026. Decommissioning and Financial Assurance Requirements The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities in the OCS.
The OBBBA also rolled back the Inflation Reduction Act’s royalty rate increase for offshore leases, returning the minimum royalty rate to 12.5% and eliminating royalty payments on natural gas produced from federal land and consumed or lost through venting, flaring or negligent release during upstream operations. 6 Table of Contents Decommissioning and Financial Assurance Requirements The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities in the OCS.
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Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which can delay production and sales of our oil and natural gas. Impact of Inflation The United States has experienced a rise in inflation since October 2021.
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We believe that our coverage limits are sufficient and are consistent with our exposure; however, we cannot insure against all possible losses.
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Inflation peaked during mid-2022 at 9.1% but the rate of inflation has been gradually declining since the second half of 2022 according to the Consumer Price Index (the “CPI”). The annual inflation rate for December 2024 was 2.9%, a decrease from the 3.4% rate for December 2023.
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The change of Presidential administration in the early part of 2025 saw promising developments in the oil and natural gas regulatory environment. On January 20, 2025, President Trump issued Executive Order 14154, Unleashing American Energy .
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However, the annual inflation rate for January 2025 was 3.0%, an increase from the 2.9% in December 2024.
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Section 3 of that Order directed heads of agencies to review existing regulations to identify agency actions that impose an undue burden on the identification, development, or use of domestic energy resources.
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Beginning in September 2024, the Federal Reserve made three cuts to the target federal funds rate, bringing the target federal funds range down to 4.25% to 4.50%, easing monetary policy for the first time in four years due to progress in inflation moving sustainably toward 2.0%.
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The Trump administration also issued Executive Order 14156, Declaring a National Energy Emergency , stating that the United States’ insufficient energy production, transportation, refining and generation constituted an unusual and extraordinary threat to the nation’s economy, national security, and foreign policy. Furthermore, on February 3, 2025, Secretary Burgum issued Secretarial Order 3418, Unleashing American Energy .
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The Summary of Economic Projections published by the Federal Reserve in December 2024 points to another 50 basis points of cuts in 2025.
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Section 4(b) of that Order directed agency officials to prepare an action plan that will include steps to suspend, revise, or rescind certain regulations. Other Regulation of the Oil and Natural Gas Industry The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities.
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However, if inflation continues to increase, it is possible the Federal Reserve would take whatever action they deem necessary to bring inflation down and to ensure price stability, including target federal funds rate increases, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could negatively impact our business.
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Pursuant to OCSLA, the President may withdraw from disposition any of the unleased lands of the OCS. On January 6, 2025, former President Biden issued two memoranda (“Withdrawal Memoranda”) under OCSLA that withdrew approximately 625 million acres of the U.S.
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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, decreases in oilfield costs typically lag behind commodity price decreases.
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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.
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Continued inflationary pressures and increased commodity prices 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.
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On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s Withdrawal Memoranda and the U.S.
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While we are experiencing some inflationary pressure for certain costs, including employees 3 Table of Contents and vendors, such cost increases did not materially impact our 2024 financial condition or results of operations, and we currently do not expect them to materially impact our 2025 financial results or operations.
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Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts. On October 2, 2025, the U.S.
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We believe that we are in substantial compliance with all such existing laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations.
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District Court for the Western District of Louisiana granted in part a motion for summary judgment filed by plaintiffs challenging the Withdrawal Memoranda, including the States of Louisiana, Alaska, Georgia and Mississippi, the Gulf Energy Alliance and the American Petroleum Institute, declaring that the Withdrawal Memoranda are unlawful because they exceed the authority granted to the President under section 12(a) of the OCSLA.
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In August 2022, Congress passed the Inflation Reduction Act (the “IRA”) which requires that the BOEM must offer at least two million acres for oil and natural gas leasing on the OCS before the BOEM can issue a lease for offshore wind development.
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The challenge to President Trump’s revocation of the Withdrawal Memoranda remains ongoing.
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The IRA also raised the royalty rate for certain offshore leases from the current 12.5% to 16.67% and capped the rate at 18.75% for ten years. In September 2023, consistent with the requirements of the IRA concerning offshore conventional and renewable energy leasing, the DOI announced its proposed 2024 – 2029 OCS Program.
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In June 2025, the public comment period on BOEM’s request for information and comments on the preparation of the 11th National OCS Program closed. In November 2025, the DOI announced the first proposal for the 2026 - 2031 OCS Program.
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The review studied the effects of four leasing options on marine, coastal and human environments and found that the impact on resources such as air quality, birds and recreational fishing was often described as “negligible.” BOEM estimates that a final environmental impact statement will not be released until September 2025, with a final decision to be made in January 2026.
Added
This proposed OCS Program includes sales of five oil and natural gas leases in the western and central Gulf of America, where existing leasing is concentrated. It also includes two lease sales (one in 2029 and one in 2030) in the eastern Gulf of America that is currently withdrawn from leasing.
Removed
Under the new rule, BOEM streamlined the criteria used to evaluate the financial health of an energy company down to two factors: (i) the company’s credit rating, and (ii) the ratio of the value of the company’s proved reserves to decommissioning liability associated with those reserves.
Added
Most of the eastern Gulf of America has not previously been leased, and no commercial production has occurred there to date. The Gulf of Mexico Energy Security Act of 2006 (the “GOMESA”) had prohibited oil and natural gas leasing in a defined area of the eastern Gulf of America.
Removed
The new rule also codifies the usage of BSEE decommissioning estimates to evaluate supplemental financial assurance requirements and allows third party guarantors (upon agreement with BOEM) to provide limited guarantees to specific amounts or specific leases instead of the blanket guarantees that have been used in the past.
Added
Although the GOMESA moratorium expired on June 30, 2022, President Trump effectively extended this moratorium for another decade by withdrawing this area from leasing consideration through June 2032. Some Members of Congress and other stakeholders wish to make the Eastern Gulf leasing moratorium permanent.
Removed
Finally, the new rule also requires a base financial assurance requirement of $500,000 for federal rights-of-use and easements (“RUEs”) to match the requirement for state RUEs. To provide the industry with flexibility to meet the new financial assurance requirements, BOEM will allow current lessees and grant holders to request phased-in payments over a three-year period.
Added
By contrast, oil and natural gas industry groups and some others have advocated for shrinking the area covered by the ban, or eliminating the ban before its scheduled expiration date.
Removed
BOEM estimates that the industry will be required to provide $6.9 billion in new financial assurances under the 6 Table of Contents new rule, which took effect on June 29, 2024.
Added
Although the public comment period on the proposed OCS Program (1st Analysis and Proposal) ended on January 23, 2026, the proposed OCS Program remains subject to further analysis, comment, revision, approval and additional comments. On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was signed into law.
Removed
Following the announcement of the new rule, a series of lawsuits from both states and industry groups have been filed against BOEM to block the implementation of the new rule. We are actively monitoring ongoing litigation with respect to the new rule.
Added
The OBBBA requires two oil and natural gas lease sales each year through 2040 in the Gulf of America region. These would be in addition to offshore oil and natural gas lease sales mandated under the 2026 – 2031 OCS Program.
Removed
Climate Change The threat of climate change continues to attract considerable public, governmental and scientific attention in the United States. President Biden made addressing climate change, including the restriction or elimination of GHG emissions, a priority in his administration’s agenda, and laws such as the IRA advance numerous climate-related objectives.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeVolatility in the energy sector, together with the higher interest rate environment, has caused and may continue to cause lenders to increase the interest rates under our credit facilities, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers.
Biggest changeVolatility in the energy sector, together with the higher interest rate environment, has caused and may continue to cause lenders to increase the interest rates under our credit facilities, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. 20 Table of Contents If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.
Such events as noted above may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have business interruption insurance. We re-evaluate the purchase of insurance, policy limits and terms annually.
Such events as noted above may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have business interruption insurance. We annually re-evaluate the purchase of insurance, policy limits and terms.
Additionally, increasing attention from consumers and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial preferences and behavior and societal pressure on companies to address climate change may result in increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, geothermal, tidal and biofuels as well as electric vehicles) and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.
Additionally, attention from consumers and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial preferences and behavior and societal pressure on companies to address climate change may result in increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, geothermal, tidal and biofuels as well as electric vehicles) and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.
However, in such an event, we might not be able to pay the holders the required repurchase price for the notes they present to us because we might not have sufficient funds available at that time, or the terms of our New Credit Agreement or other agreements we may enter into in the future may prevent us from applying funds to repurchase the 10.75% Notes.
However, in such an event, we might not be able to pay the holders the required repurchase price for the notes they present to us because we might not have sufficient funds available at that time, or the terms of our Credit Agreement or other agreements we may enter into in the future may prevent us from applying funds to repurchase the 10.75% Notes.
We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us from the restrictive covenants under our 2025 Indenture and our New Credit Agreement. A breach of any covenant in the agreements governing our debt would result in a default under such agreement after any applicable grace periods.
We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us from the restrictive covenants under our 2025 Indenture and our Credit Agreement. A breach of any covenant in the agreements governing our debt would result in a default under such agreement after any applicable grace periods.
Our competitors may also be able to pay more to acquire productive oil and natural gas properties and exploratory prospects than we are able or willing to pay or finance. Finally, companies with larger financial resources may have a significant advantage in terms of meeting any potential new bonding requirements.
Our competitors may also be able to pay more to acquire productive oil and natural gas properties and exploratory prospects than we are able or willing to pay or finance. Finally, companies with larger financial resources may have a significant advantage in terms of meeting any potential new bonding or financial assurance requirements.
District Court for the Southern District of Texas, Houston Division, against Endurance Assurance Corporation and Lexon Insurance Company (the “Sompo Sureties”), providers of government-required surety bonds that secure decommissioning obligations we may have with respect to certain of our oil and natural gas assets (the “Sompo Sureties Litigation”).
District Court for the Southern District of Texas, Houston Division, against Endurance Assurance Corporation and Lexon Insurance Company (the “Sompo Sureties”), providers of private and government-required surety bonds that secure decommissioning obligations we may have with respect to certain of our oil and natural gas assets (the “Sompo Sureties Litigation”).
Our New Credit Agreement requires us, among other things, to maintain certain financial ratios and satisfy certain financial condition tests. These restrictions may also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities.
Our Credit Agreement requires us, among other things, to maintain certain financial ratios and satisfy certain financial condition tests. These restrictions may also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities.
If we default on our secured debt, the value of the collateral securing our secured debt may not be sufficient to ensure repayment of all of such debt. Our New Credit Agreement and our 10.75% Notes are secured by various liens on our oil and natural gas properties.
If we default on our secured debt, the value of the collateral securing our secured debt may not be sufficient to ensure repayment of all of such debt. Our Credit Agreement and our 10.75% Notes are secured by various liens on our oil and natural gas properties.
The source of funds for any repurchase required as a result of a change of control will be our available cash or cash generated from our oil and gas operations or other sources, including: ● borrowings under the New Credit Agreement or other sources; ● sales of assets; or ● sales of equity.
The source of funds for any repurchase required as a result of a change of control will be our available cash or cash generated from our oil and gas operations or other sources, including: ● borrowings under the Credit Agreement or other sources; ● sales of assets; or ● sales of equity.
See Financial Statements and Supplementary Data– Note 11 –Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on our derivative contracts and transactions.
See Financial Statements and Supplementary Data– Note 10 –Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on our derivative contracts and transactions.
The indenture (the “2025 Indenture”) governing our 10.75% Notes and our New Credit Agreement contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt.
The indenture (the “2025 Indenture”) governing our 10.75% Notes and our Credit Agreement contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt.
Increasing attention to climate change, for example, may result in demand shifts for the hydrocarbon products we produce as well as additional governmental investigations and private litigation against us.
Attention to climate change, for example, may result in demand shifts for the hydrocarbon products we produce as well as additional governmental investigations and private litigation against us.
The occurrence of a significant event for which our losses are not fully insured or indemnified, or for which the insurance companies will not pay our claims, could have a material adverse effect on our financial condition and results of operations. 15 Table of Contents In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations.
The occurrence of a significant event for which our losses are not fully insured or indemnified, or for which the insurance companies will not pay our claims, could have a material adverse effect on our financial condition and results of operations. 14 Table of Contents In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations.
Additionally, litigation risks to oil and natural gas companies are increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
Additionally, litigation risks to oil and natural gas companies are increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately 28 Table of Contents disclose those impacts.
Gulf Coast; ● technological advances affecting energy consumption and the availability and cost of alternative energy sources; ● the price, availability and acceptance of alternative fuels; ● speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; ● cyberattacks on our information infrastructure or systems controlling offshore equipment; ● activities by non-governmental organizations to restrict the exploration and production of oil and natural gas so as to minimize or eliminate future emissions of carbon dioxide, methane gas and other GHGs; ● the effect of energy conservation efforts; ● the availability of pipeline and other transportation alternatives and third-party processing capacity; and ● geographic differences in pricing.
Gulf Coast; ● technological advances affecting energy consumption and the availability and cost of alternative energy sources; ● the price, availability and acceptance of alternative fuels; ● speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; ● cyberattacks on our information infrastructure or systems controlling offshore equipment; ● activities by non-governmental organizations to restrict the exploration and production of oil and natural gas so as to minimize or eliminate future emissions of carbon dioxide, methane gas and other GHGs; ● the effect of energy conservation efforts; 11 Table of Contents ● the availability of pipeline and other transportation alternatives and third-party processing capacity; and ● geographic differences in pricing.
Any future borrowings under our New Credit Agreement would be secured on a first priority basis by the assets securing the 10.75% Notes.
Any future borrowings under our Credit Agreement would be secured on a first priority basis by the assets securing the 10.75% Notes.
In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, and that may in the future, allow them to implement new technologies before we can. We rely heavily on the use of advanced seismic technology to identify exploitation opportunities and to reduce our 17 Table of Contents geological risk.
In addition, competitors may have greater financial, 16 Table of Contents technical and personnel resources that allow them to enjoy technological advantages, and that may in the future, allow them to implement new technologies before we can. We rely heavily on the use of advanced seismic technology to identify exploitation opportunities and to reduce our geological risk.
Impairments of our oil and gas properties are more likely to occur during prolonged periods of depressed oil, NGLs and natural gas pricing. While we have not recorded an impairment of our oil and gas properties during 2024, any further decreases in commodity pricing could cause an impairment, which would result in a non-cash charge to earnings.
Impairments of our oil and gas properties are more likely to occur during prolonged periods of depressed oil, NGLs and natural gas pricing. While we have not recorded an impairment of our oil and gas properties during 2025, any further decreases in commodity pricing could cause an impairment, which would result in a non-cash charge to earnings.
Further, we are incorporated in Texas. The Texas Business Organizations Code contains certain provisions that could make an acquisition by a third party more difficult. ​ 31 Table of Contents While we paid quarterly dividends during 2024, there can be no assurance that we will pay dividends in the future.
Further, we are incorporated in Texas. The Texas Business Organizations Code contains certain provisions that could make an acquisition by a third party more difficult. 31 Table of Contents While we paid quarterly dividends during 2025, there can be no assurance that we will pay dividends in the future.
In January 2025, we issued $350.0 million in aggregate principal amount of our 10.75% Senior Second Lien Notes due 2029 (the “10.75% Notes”) and entered into a new credit agreement with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million (the “New Credit Agreement”).
In January 2025, we issued $350.0 million in aggregate principal amount of our 10.75% Senior Second Lien Notes due 2029 (the “10.75% Notes”) and entered into a new credit agreement with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million (the “Credit Agreement”).
Further, current market conditions may adversely impact our ability to obtain financing to fund acquisitions, and further lower the level of activity and depressed values in the oil and natural gas property sales market. We are not insured against all of the operating risks to which our business is exposed.
Further, current market conditions may adversely impact our ability to obtain financing to fund acquisitions, and further lower the level of activity and depress values in the oil and natural gas property sales market. We are not insured against all of the operating risks to which our business is exposed.
These covenants limit our ability and the ability of certain subsidiaries, among other things, to: ● make loans and investments; ● incur or guarantee additional indebtedness; ● create certain liens; 20 Table of Contents ● transfer or sell assets; ● enter into agreements that restrict dividends or other payments from our subsidiaries to us; ● consolidate, merge or transfer all or substantially all of the assets of the Company; ● enter into transactions with our affiliates; ● pay dividends or make other distributions on capital stock or subordinated indebtedness; and ● create subsidiaries that would not be restricted by the covenants of the 2025 Indenture.
These covenants limit our ability and the ability of certain subsidiaries, among other things, to: ● make loans and investments; ● incur or guarantee additional indebtedness; ● create certain liens; ● transfer or sell assets; ● enter into agreements that restrict dividends or other payments from our subsidiaries to us; ● consolidate, merge or transfer all or substantially all of the assets of the Company; ● enter into transactions with our affiliates; ● pay dividends or make other distributions on capital stock or subordinated indebtedness; and ● create subsidiaries that would not be restricted by the covenants of the 2025 Indenture.
Additionally, our properties are located in deepwater, which generally increases the capital and operating costs, technical challenges and risks associated with exploration and production activities. As a result, our exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable production.
Additionally, some of our properties are located in deepwater, which generally increases the capital and operating costs, technical challenges and risks associated with exploration and production activities. As a result, our exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable production.
It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of our reserves at December 31, 2024.
It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of our reserves at December 31, 2025.
Increasing scrutiny related to ESG matters, societal expectations for companies to address climate change and sustainability concerns, and investor, societal, and other stakeholder expectations regarding ESG and sustainability practices and related disclosures may result in increased costs, reduced demand for the oil and natural gas we produce, reduced profits, increased risks of governmental investigations and private party litigation, and negative impacts on our stock price and access to capital markets.
Increasing scrutiny related to ESG matters, societal expectations for companies to address climate change and sustainability concerns, and investor, societal, and other stakeholder expectations regarding ESG and sustainability 29 Table of Contents practices and related disclosures may result in increased costs, reduced demand for the oil and natural gas we produce, reduced profits, increased risks of governmental investigations and private party litigation, and negative impacts on our stock price and access to capital markets.
While we have established AROs for well decommissioning, additional AROs, significant in amount, may be necessary to conduct plugging and abandonment of the wells designated in the future as idle iron, but we do not expect the costs to plug and abandon such additional wells will have a material effect on our financial condition, results of operations or cash flows.
While we have established AROs for well decommissioning, additional AROs, significant in amount, may be necessary to conduct plugging and abandonment of the wells designated in the future as idle iron, but we do not expect the costs to plug and abandon such additional wells will have a material 25 Table of Contents effect on our financial condition, results of operations or cash flows.
If we fail to obtain permits in a timely manner or at all (for example, due to opposition from community or environmental groups, government delays, changes in laws or the interpretation thereof, or any other reason), such failure could impede our operations, which could have a material adverse effect on our results of operations and our financial condition.
If we fail to obtain permits in a timely manner or at all (for example, due to opposition from community or environmental groups, government delays, changes in laws or the interpretation thereof, or any other reason), such 23 Table of Contents failure could impede our operations, which could have a material adverse effect on our results of operations and our financial condition.
Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect.
Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that 30 Table of Contents also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect.
The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital. ​ 16 Table of Contents We are subject to drilling and other operational hazards.
The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital. 15 Table of Contents We are subject to drilling and other operational hazards.
Sustained low oil, NGLs and natural gas pricing may also significantly impact the projected rates of return of our projects without the assurance of significant reductions in costs of drilling and development. To the extent we drill additional wells in the deepwater and/or on the deep shelf, our drilling activities could become more expensive.
Sustained low oil, NGLs and natural gas pricing may also 17 Table of Contents significantly impact the projected rates of return of our projects without the assurance of significant reductions in costs of drilling and development. To the extent we drill additional wells in the deepwater and/or on the deep shelf, our drilling activities could become more expensive.
See our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K for more information regarding our senior management team. 19 Table of Contents There may be circumstances in which the interests of significant stockholders could conflict with the interests of our other stockholders.
See our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K for more information regarding our senior management team. There may be circumstances in which the interests of significant stockholders could conflict with the interests of our other stockholders.
On October 25, 2024, we filed a notice of removal with the District Court of Harris County, Texas, removing the case to U.S. District Court for the 22 Table of Contents Southern District of Texas, Houston Division. USSIC has issued approximately $111.0 million in surety bonds on our behalf and has requested $23.0 million in cash collateral.
On October 25, 2024, we filed a notice of removal with the District Court of Harris County, Texas, removing the case to U.S. District Court for the Southern District of Texas, Houston Division. USSIC has issued approximately $111.0 million in surety bonds on our behalf and has requested $23.0 million in cash collateral.
These shut-ins resulted in deferred production of approximately 850 MBoe based on production rates prior to the shut-ins. Any additional shut-ins, depending on the duration of the shut-in, could have a material adverse impact on our business.
These shut-ins resulted in deferred production of approximately 686 MBoe based on production rates prior to the shut-ins. Any additional shut-ins, depending on the duration of the shut-in, could have a material adverse impact on our business.
Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with such legal requirements may harm our business, results of operations and financial condition. 26 Table of Contents Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a result of regulatory requirements or restrictions.
Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with such legal requirements may harm our business, results of operations and financial condition. Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a result of regulatory requirements or restrictions.
If the proceeds of the sale of the collateral securing the 10.75% Notes or any future indebtedness incurred under the New Credit Agreement are not sufficient to repay all amounts due in respect of such debt, then claims against our remaining assets to repay any amounts still outstanding under our secured obligations would be unsecured, 21 Table of Contents and our ability to pay our other unsecured obligations and any distributions in respect of our capital stock would be significantly impaired.
If the proceeds of the sale of the collateral securing the 10.75% Notes or any future indebtedness incurred under the Credit Agreement are not sufficient to repay all amounts due in respect of such debt, then claims against our remaining assets to repay any amounts still outstanding under our secured obligations would be unsecured, and our ability to pay our other unsecured obligations and any distributions in respect of our capital stock would be significantly impaired.
Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. This could also result in an 28 Table of Contents increase in our expenses and a reduction of available capital funding for potential development projects, impacting our future financial results.
Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. This could also result in an increase in our expenses and a reduction of available capital funding for potential development projects, impacting our future financial results.
This concentration means that any impact on our production from this field, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment or otherwise, could have a material adverse effect on our business. During 2024, our Mobile Bay Properties were shut-in for various reasons, including Hurricane Helene, compressor problems and downstream operated plant issues.
This concentration means that any impact on our production from this field, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment or otherwise, could have a material adverse effect on our business. During 2025, our Mobile Bay Properties were shut-in for various reasons, including compressor problems and downstream operated plant issues.
In addition, if we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted, and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures.
In addition, if we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted, and we may be required to seek 24 Table of Contents alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures.
Such circumstances or conflicts might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership and lender relationships may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning shares in companies with significant stockholder concentrations or with such potential conflicts.
Such circumstances or conflicts might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning shares in companies with significant stockholder concentrations or with such potential conflicts.
Commodity derivative positions may limit our potential gains. In order to manage our exposure to price risk in the marketing of our production, we have entered into commodity derivative positions with respect to a portion of our expected future production from natural gas, and may in the future enter into commodity derivative positions with respect to oil or natural gas.
In order to manage our exposure to price risk in the marketing of our production, we have entered into commodity derivative positions with respect to a portion of our expected future production from oil and natural gas, and may in the future enter into commodity derivative positions with respect to oil or natural gas.
At December 31, 2024, approximately 17% of our estimated proved reserves (by volume) were undeveloped. Any or all of our PUD reserves may not be ultimately developed or produced or may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves.
At December 31, 2025, approximately 6% of our estimated proved reserves (by volume) were undeveloped. Any or all of our PUD reserves may not be ultimately developed or produced or may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves.
Historically, oil, NGLs and natural gas prices have been volatile and subject to wide price fluctuations in response to domestic and global changes in supply and demand, economic and legal forces, events and uncertainties, and numerous other factors beyond our control, including: ● general economic conditions and level of economic growth, including low or negative growth; ● changes in global supply and demand for oil, NGLs and natural gas; ● events that impact global market demand, such as a pandemic or other world health event; ● production quotas or other actions that might be imposed by OPEC+; ● the price and quantity of imports of foreign oil, NGLs, natural gas and liquefied natural gas into the U.S.; ● acts of war, terrorism or political instability in oil producing countries (e.g. the invasion of Ukraine by Russia and conflicts in the Middle East); ● domestic and foreign governmental regulations and taxes; ● U.S. federal, state and foreign government policies and regulations regarding current and future exploration and development of oil and gas; ● political conditions and events, including embargoes and moratoriums, affecting oil-producing activities; ● the level of domestic and global oil and natural gas exploration and production activities; ● the level of global oil, NGLs and natural gas inventories; ● adverse weather conditions and exceptional weather conditions, including severe weather events in the U.S.
Historically, oil, NGLs and natural gas prices have been volatile and subject to wide price fluctuations in response to domestic and global changes in supply and demand, economic and legal forces, events and uncertainties, and numerous other factors beyond our control, including: ● general economic conditions and level of economic growth, including low or negative growth; ● changes in global supply and demand for oil, NGLs and natural gas; ● events that impact global market demand, such as a pandemic or other world health event; ● production quotas or other actions that might be imposed by OPEC+, including a potential increase in OPEC+ oil supply and any related impact on global oil prices and domestic oil production; ● the price and quantity of imports of foreign oil, NGLs, natural gas and liquefied natural gas into the U.S.; ● acts of war, terrorism or political instability in oil producing countries (e.g. the invasion of Ukraine by Russia and conflicts in the Middle East, including the recent escalation involving Iran and recent U.S. intervention in Venezuela); ● domestic and foreign governmental regulations and taxes; ● U.S. federal, state and foreign government policies and regulations regarding current and future exploration and development of oil and gas; ● political conditions and events, including embargoes and moratoriums, affecting oil-producing activities; ● the level of domestic and global oil and natural gas exploration and production activities; ● the level of global oil, NGLs and natural gas inventories; ● adverse weather conditions and exceptional weather conditions, including severe weather events in the U.S.
You should not assume that the standardized measure or the present value of future net revenues from our proved oil and natural gas reserves is the current market value of our estimated oil and natural gas reserves.
You should not assume that the standardized measure of discounted future net cash flows or the present value of future net revenues from our proved oil and natural gas reserves is the current market value of our estimated oil and natural gas reserves.
The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and 13 Table of Contents the proximity of reserves to pipelines and terminal facilities.
The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities.
In addition, the geological complexity of deepwater and deep shelf 18 Table of Contents formations may make it more difficult for us to sustain our historical rates of drilling success.
In addition, the geological complexity of deepwater and deep shelf formations may make it more difficult for us to sustain our historical rates of drilling success.
If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted. Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted. 12 Table of Contents Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for future bonds. On August 14, 2024, we filed a complaint seeking declaratory relief (the “Original Complaint”) in the U.S.
We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for future bonds. 21 Table of Contents On August 14, 2024, we filed a complaint seeking declaratory relief (the “Original Complaint”) in the U.S.
Increasing attention to ESG matters may impact our business.
Attention to ESG matters may impact our business.
Financial Statements and Supplementary Data — Note 6 — Commitments and Contingencies for more information. We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Financial Statements and Supplementary Data — Note 5 — Commitments and Contingencies for more information. We are subject to numerous laws, rules, regulations and policies that can adversely affect the cost, manner or feasibility of doing business.
Under certain circumstances, regulations or federal laws, such as the OCSLA, could impose joint and several strict liability and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2024, we have $22.6 million of loss contingency recorded related to anticipated decommissioning obligations. See Part II, Item 8.
Under certain circumstances, regulations or federal laws, such as the OCSLA, could impose joint and several strict liability and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2025, we have $36.2 million of loss contingency recorded related to anticipated decommissioning obligations. See Part II, Item 8.
For 2024, approximately 35% of our production and 15% of our total revenue was attributable to our interests in certain oil and natural gas leasehold interests and associated wells and units located off the coast of Alabama, in state coastal and federal Gulf of America waters approximately 70 miles south of Mobile, Alabama (the “Mobile Bay Properties”).
For 2025, approximately 36% of our production and 20% of our total revenue was attributable to our interests in certain oil and natural gas leasehold interests and associated wells and units located off the coast of Alabama, in state coastal and federal Gulf of America waters approximately 70 miles south of Mobile, Alabama (the “Mobile Bay Properties”).
In addition, extended periods or low commodity prices can have a material 12 Table of Contents adverse impact on the results of operations, financial condition and liquidity of our suppliers, vendors, partners and customers upon which our own results of operations and financial condition depends.
In addition, extended periods or low commodity prices can have a material adverse impact on the results of operations, financial condition and liquidity of our suppliers, vendors, partners and customers upon which our own results of operations and financial condition depend.
Capital Risks Our debt level could negatively affect our financial condition, results of operations and business prospects. As of December 31, 2024, we had $399.1 million of principal amount of long-term debt outstanding.
Capital Risks Our debt level could negatively affect our financial condition, results of operations and business prospects. As of December 31, 2025, we had $358.8 million of principal amount of long-term debt outstanding.
In addition, third-party platforms could be damaged or destroyed by tropical storms, hurricanes or other weather events, which could reduce or eliminate our ability to market our production. As of December 31, 2024, four fields, accounting for approximately 3.7 MMBoe (or 2.9%) of our total proved reserves, are tied back to separate, third-party owned platforms.
In addition, third-party platforms could be damaged or destroyed by tropical storms, hurricanes or other weather events, which could reduce or eliminate our ability to market our production. As of December 31, 2025, two fields, accounting for approximately 1.0 MMBoe (or 0.8%) of our total proved reserves, are tied back to separate, third-party owned platforms.
The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows. 30 Table of Contents Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.
The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
If we fail to comply with the new rule and such future orders, the BOEM could commence enforcement proceedings or take other remedial action against us, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.
A failure to comply with BOEM’s financial assurance requirements could cause BOEM to commence enforcement proceedings or take other remedial action against us, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.
We may not realize all of the anticipated benefits from future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices. This could lead to potential adverse short-term or long-term effects on our operating results.
We may not realize all of the anticipated benefits from future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.
We are subject to laws, rules, regulations and policies regarding data privacy and security. Many of these laws and regulations are subject to change and reinterpretation, and could result in claims, changes to our business practices, monetary penalties, increased cost of operations or other harm to our business.
Many of these laws and regulations are subject to change and reinterpretation, and could result in claims, changes to our business practices, monetary penalties, increased cost of operations or other harm to our business. We are subject to a variety of federal, state and local laws, directives, rules and policies relating to data privacy and cybersecurity.
Our independent petroleum consultant estimates that 36.4% of our total proved reserves as of December 31, 2024 will be depleted within three years.
Our independent petroleum consultant estimates that 34.0% of our total proved reserves as of December 31, 2025 will be depleted within three years.
This could decrease demand for oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business. 27 Table of Contents We are subject to risks arising from climate change, including risks related to energy transition, which could result in increased costs and reduced demand for the oil and natural gas we produce and physical risks which could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
We are subject to risks arising from climate change, including risks related to energy transition, which could result in increased costs and reduced demand for the oil and natural gas we produce and physical risks which could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected. 29 Table of Contents Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others.
If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected.
Although we take security measures to protect against cybersecurity risks, including unauthorized access to our confidential and proprietary information, our security measures may not be able to detect or prevent every attempted breach. Similar to other companies, we have experienced cyber-attacks, although we have not suffered any material losses related to such attacks.
Although we take security measures to protect against cybersecurity risks, including unauthorized access to our confidential and proprietary information, our security measures may not be able to detect or prevent every attempted breach.
We do not maintain or plan to obtain for the benefit of the Company any insurance against the loss of any of these individuals.
The loss of the services of any of our senior management could have a negative impact on our operations. We do not maintain or plan to obtain for the benefit of the Company any insurance against the loss of any of these individuals.
Any of these security breaches could have a material adverse effect on our consolidated financial position, results of operations and cash flows. The invasion of Ukraine by Russia, and the impact of world sanctions against Russia and the potential for retaliatory acts from Russia, could result in increased cybersecurity attacks against U.S. companies.
Any of these security breaches could have a material adverse effect on our consolidated financial position, results of operations and cash flows. Geopolitical tensions, sanctions, and retaliatory actions could result in increased cybersecurity attacks against U.S. companies. Acquisitions and emerging technologies may increase our cybersecurity risk.
New technologies may cause our current exploration and drilling methods to become obsolete, and we may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies.
New technologies may cause our current exploration and drilling methods to become obsolete, and we may not be able to keep pace with technological developments in our industry.
We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. See Business – Environmental, Health and Safety Matters and Regulations and Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 in this Form 10-K for a more detailed explanation of regulations impacting our business.
See Business – Environmental, Health and Safety Matters and Regulations and Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 in this Form 10-K for a more detailed explanation of regulations impacting our business. 26 Table of Contents We are subject to laws, rules, regulations and policies regarding data privacy and security.
Since taking office in January 2025, President Trump has taken actions to reverse many of these Biden-era rules and policies. President Trump in January 2025 issued additional executive orders aimed at boosting fossil fuels and undoing Biden-era initiatives to limit GHG emissions. He declared a national energy emergency and revoked many of Biden’s executive orders on climate change.
In January 2025, President Trump announced that the United States was withdrawing from the United Nations-sponsored “Paris Agreement.” He also issued additional executive orders aimed at boosting fossil fuels and undoing Biden-era initiatives to limit GHG emissions. He declared a national energy emergency and revoked many of Biden’s executive orders on climate change.
However, we may not be able to accomplish any of these transactions on terms acceptable to us or such actions may not yield sufficient capital to meet our obligations. Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
However, we may not be able to accomplish any of these transactions on terms acceptable to us or such actions may not yield sufficient capital to meet our obligations.
It is also possible that inquiries from governmental authorities regarding cybersecurity breaches increase in frequency and scope. These data privacy and cybersecurity laws also are not uniform, which may complicate and increase our costs for compliance.
These data privacy and cybersecurity laws also are not uniform, which may complicate and increase our costs for compliance.
To the extent we are unable to secure adequate financing, we may be: forced to reduce our capital expenditures in the current year or future years; unable to execute our ARO plan; or unable to comply with our existing debt instruments. ​ 23 Table of Contents Legal, Government and Regulatory Risks We are subject to numerous environmental, health and safety regulations which are subject to change and may also result in material liabilities and costs.
To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures in the current year or future years; unable to execute our ARO plan; or unable to comply with our existing debt instruments.
While we are working to find an alternative path to market, we are unable to realize revenues from our production at the affected properties until such time as an alternative arrangement is made. 14 Table of Contents Operating Risks Production periods and relatively short reserve lives for our Gulf of America properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil, NGL and natural gas prices.
If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to process or deliver our production to market. 13 Table of Contents Operating Risks Production periods and relatively short reserve lives for our Gulf of America properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil, NGL and natural gas prices.
Our debt agreements contain restrictions that limit our abilities to incur certain additional debt or liens or engage in other transactions, which could limit growth and our ability to respond to changing conditions.
Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations. 19 Table of Contents Our debt agreements contain restrictions that limit our abilities to incur certain additional debt or liens or engage in other transactions, which could limit growth and our ability to respond to changing conditions.
Our future acquisitions and divestitures could expose us to potentially significant liabilities, including plugging and abandonment and decommissioning liabilities .
This could lead to potential adverse short-term or long-term effects on our financial and operating results. Our future acquisitions and divestitures could expose us to potentially significant liabilities, including plugging and abandonment and decommissioning liabilities .
In addition, the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives.
These incentives offered for various clean energy industries could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. This could decrease demand for oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.
As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost.
As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies, provide enhancements and new integrations from our existing platforms, develop new products that achieve market acceptance or innovate quickly enough to keep pace with rapid technological developments at a substantial cost.
As of December 31, 2024, we operate 86.1% of our wells. As we carry out our drilling program, we may not serve as operator of all planned wells. In that case, we have limited ability to exercise influence over the operations of some non-operated properties and their associated costs.
As of December 31, 2025, we operate 86.7% of our wells. For those wells that we do not operate, we have limited ability to exercise influence over the operations and their associated costs.
We are subject to a variety of federal, state and local laws, directives, rules and policies relating to data privacy and cybersecurity. The regulatory framework for data privacy and cybersecurity worldwide is continuously evolving and developing, and, as a result, interpretation and implementation standards and enforcement practices are likely to remain uncertain for the foreseeable future.
The regulatory framework for data privacy and cybersecurity worldwide is continuously evolving and developing, and, as a result, interpretation and implementation standards and enforcement practices are likely to remain uncertain for the foreseeable future. It is also possible that inquiries from governmental authorities regarding cybersecurity breaches increase in frequency and scope.
Business – Environmental, Health and Safety Matters and Regulations and Other Regulation of the Oil and Natural Gas Industry for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry. 25 Table of Contents Our estimates of future ARO may vary significantly from period to period, and unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.
Business – Environmental, Health and Safety Matters and Regulations and Other Regulation of the Oil and Natural Gas Industry for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry.
Security breaches include, among other things, illegal hacking, computer viruses, interference with treasury function, theft or acts of vandalism or terrorism.
Similar to other companies, we have experienced cyber-attacks, although we have not suffered any material losses related to such attacks as of the date of this Form 10-K. Security breaches include, among other things, illegal hacking, computer viruses, interference with treasury function, theft or acts of vandalism or terrorism.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeOur CIO has extensive information security and risk management experience in Information and Operational technology and holds the following information security certifications: 32 Table of Contents ● Certified Information Systems Security Professional (CISSP); ● Certified Information Systems Auditor (CISA); and ● Certified Risk and Information Systems Control (CRISC).
Biggest changeOur CIO & CISO brings extensive experience in both Information Technology and Operational Technology security and holds the following professional certifications: ● Certified Information Systems Security Professional (CISSP) ● Certified Information Systems Auditor (CISA) ● Certified in Risk and Information Systems Control (CRISC) In addition to these credentials, our CIO & CISO is an active member of InfraGard, ISC2, and ISACA, and serves as an advisory board member for multiple cybersecurity industry organizations. 32 Table of Contents We require all employees to complete mandatory security training during onboarding and annual refresher training thereafter.
We require each third-party service provider to certify that it has the ability to implement and maintain appropriate security measures, consistent with all applicable laws, to implement and maintain reasonable security measures in connection with their work with us, and to promptly report any suspected breach of its security measures that may affect us.
We require each third-party service provider to certify that it has the ability to implement and maintain appropriate security measures, consistent with all applicable laws, to implement and maintain reasonable security measures in connection with their work with us, and to promptly report any issues that may affect us.
ITEM 1C. CYBERSECURITY We maintain a cyber risk management program designed to identify, assess, manage, mitigate, and respond to cybersecurity threats. This program is integrated within our IT and risk management systems and addresses both the corporate and the operational IT environment.
ITEM 1C. CYBERSECURITY We maintain a comprehensive cyber risk management program designed to identify, assess, mitigate, and monitor cybersecurity threats across both our corporate and operational technology environments. This program is integrated within our IT and risk management systems and addresses both the corporate and the operational IT environment.
We face risks from cybersecurity threats that could have a material adverse effect on our business, financial condition, results of operations, cash flows or reputation. To our knowledge, such risks have not materially affected our operations nor have we experienced any cybersecurity incidences which have impacted our operations.
While cybersecurity threats remain an inherent risk to all organizations and we face risks from cybersecurity threats that could have a material adverse effect on our business, financial condition, results of operations, cash flows or reputation, our robust risk management strategies have been effective.
We also engage certain third-parties in assessing, identifying and managing cyber-security risks. These third parties perform a number of services, including managed detection and response services for information technology endpoints, anti-virus monitoring, penetration testing, and other miscellaneous cyber security programs and services. We maintain specific policies and practices governing our third-party security risks, including our third-party assessment process.
We also engage qualified third-party partners to support key cybersecurity functions, including managed detection and response, antivirus monitoring, penetration testing, and other specialized services. We maintain specific policies and practices governing our third-party security risks, including our third-party assessment process.
Our Incident Response Plan applies to our personnel including contractors and partners that perform functions or services that require securing our information assets, and to all devices and networks that we own. The Incident Response Plan details the coordinated, multi-functional approach for investigating, containing, and mitigating incidents.
We maintain a structured incident-response framework consistent with NIST guidelines, ensuring that any security events are promptly identified, assessed, and escalated to the appropriate leadership. Our incident response framework applies to our personnel, including contractors and partners that perform functions or services that require securing our information assets, and to all devices and networks that we own.
Regular updates are provided by the Cybersecurity team to the CIO, who will maintain communication and information flow to senior leadership including the General Counsel, Chief Financial Officer, and other cybersecurity program stakeholders as well as the Audit Committee and/or the Board of Directors as appropriate.
Cybersecurity incidents are escalated based on predefined criteria to our Chief Information Officer (“CIO”) & Chief Information Security Officer (“CISO”), General Counsel, senior leadership, and, when appropriate, the Audit Committee and our board of directors. The program is led by our CIO and CISO, who oversees the identification and management of information security risks.
Removed
The underlying controls of the cyber risk management program are based on recognized best practices and standards for cybersecurity and IT, including the National Institute of Standards and Technology (the “NIST”), the Control Objectives for Information Technologies (“COBIT”) framework and the International Organization Standardization 27001, Information Security Management System requirements.
Added
Our program is aligned with recognized industry standards, including the National Institute of Standards and Technology (the “NIST”), the Control Objectives for Information Technologies and ISO 27001, and is evaluated annually by our internal audit department against these frameworks. Our information security practices emphasize strong governance, well-defined policies and continuous improvement to safeguard critical systems and data.
Removed
We have an annual assessment, performed by our internal audit department, of our cyber risk management program against the NIST and COBIT frameworks. Our information security practices include development, implementation, and improvement of policies and procedures to safeguard information and ensure availability of critical data and systems.
Added
The response framework details the coordinated, multi-functional approach for investigating, containing, and mitigating incidents. This process supports coordinated decision-making and maintains clear communication with senior management and our board of directors when necessary.
Removed
We have adopted a Cybersecurity Incident Response Plan that applies if a security event occurs. Our Incident Response Plan provides a common framework for responding to security incidents. This framework establishes procedures for identifying, validating, categorizing, documenting, and responding to security events that are identified by or reported to the Chief Information Officer ( “CIO ”) .
Added
Oversight of our cybersecurity program is provided by the Audit Committee of the board of directors. Executive leadership, including the CIO & CISO provides regular updates—at least quarterly—on cybersecurity risks, program maturity, and mitigation strategies.
Removed
Under our Incident Response Plan, cybersecurity incidents are escalated based on a defined incident categorization to the CIO and the General Counsel.
Added
Accordingly, to our knowledge, over the past three years we have not experienced any material cybersecurity incidents, and such risks have not materially affected and are not reasonably likely to materially affect, our business strategy, results of operations or financial condition.
Removed
Generally, our incident response process follows the National Institute of Standards and Technology (NIST) framework and focuses on preparation; detection and analysis; containment, eradication, recovery and post-incident remediation. Our CIO leads the information security organization which oversees the identification and management of information security risks.
Added
We continue to monitor and strengthen our defenses as part of our ongoing commitment to protecting our business operations, financial performance, and reputation.
Removed
Our CIO is a member of InfraGard, ISC2 and ISACA and serves as Adjunct Professor of Cyber Security at Lone Star College and San Jacinto College. We conduct mandatory security training during new employee onboarding, as well as require our employees to complete annual security risk training and, when necessary, perform additional updated training.
Removed
The Audit Committee of our board of directors oversees our cybersecurity policies, procedures, risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks.
Removed
Our executive management, including our Vice President and Chief Information Officer, periodically updates and reports to the Audit Committee and the board of directors regarding cybersecurity risk exposure and our cybersecurity risk management strategy (at a minimum, once per quarter).
Removed
In the past three years, we have not experienced a material information security breach. We will continue to face cybersecurity threats whether directly or through our supply chain or other channels in the normal course of business. See Risk Factors in Part I, Item 1A in this Form 10-K for additional information.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeThe table below provides a reconciliation of PV-10 and PV-10 before ARO to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves (in millions): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2024 ​ 2023 ​ 2022 PV-10 ​ $ 1,229.5 ​ $ 1,080.9 ​ $ 3,128.6 ​ Future income taxes, discounted at 10% ​ (154.8) ​ (151.0) ​ (594.1) ​ PV-10 before ARO ​ 1,074.7 ​ 929.9 ​ 2,534.5 ​ Present value of estimated ARO, discounted at 10% ​ (334.6) ​ (246.7) ​ (271.5) ​ Standardized measure ​ $ 740.1 ​ $ 683.2 ​ $ 2,263.0 ​ ​ ​ 35 Table of Contents Changes in Proved Reserves The following table discloses our estimated changes in proved reserves during 2024: ​ ​ ​ ​ ​ MMBoe Proved reserves at December 31, 2023 ​ 123.0 Reserves additions (reductions): ​ ​ Revisions (1) (5.5) Purchases of minerals in place 21.7 Production (12.2) Net reserve additions (reductions) ​ 4.0 Total proved reserves at December 31, 2024 127.0 ​ (1) Net revisions are primarily attributable to lower commodity prices.
Biggest changeThe table below provides a reconciliation of PV-10 and PV-10 before ARO to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves (in millions): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2025 ​ 2024 ​ 2023 PV-10 ​ $ 1,115.3 ​ $ 1,229.5 ​ $ 1,080.9 ​ Future income taxes, discounted at 10% ​ (130.8) ​ (154.8) ​ (151.0) ​ PV-10 before ARO ​ 984.5 ​ 1,074.7 ​ 929.9 ​ Present value of estimated ARO, discounted at 10% ​ (333.2) ​ (334.6) ​ (246.7) ​ Standardized measure of discounted future net cash flows ​ $ 651.3 ​ $ 740.1 ​ $ 683.2 ​ ​ Changes in Proved Reserves The following table discloses our estimated changes in proved reserves during 2025: ​ ​ ​ ​ ​ MMBoe Proved reserves at December 31, 2024 ​ 127.0 Reserves additions (reductions): ​ ​ Net revisions (1) 6.5 Sale of minerals in place (0.1) Production (12.4) Net reserve additions (reductions) ​ (6.0) Total proved reserves at December 31, 2025 121.0 ​ (1) Net revisions are primarily attributable to higher prices for natural gas partially offset by lower oil prices and a decrease in the number of PUD locations.
Our estimated proved reserve information as of December 31, 2024 included in this Form 10-K was prepared by our independent petroleum consultants, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.
Our estimated proved reserve information as of December 31, 2025 included in this Form 10-K was prepared by our independent petroleum consultants, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.
The accuracy of the estimates of our reserves is a function of: ● the quality and quantity of available data and the engineering and geological interpretation of that data; ● estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results; 37 Table of Contents ● the accuracy of various mandated economic assumptions such as the future prices of oil, NGLs and natural gas; and ● the judgment of the persons preparing the estimates.
The accuracy of the estimates of our reserves is a function of: ● the quality and quantity of available data and the engineering and geological interpretation of that data; ● estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results; ● the accuracy of various mandated economic assumptions such as the future prices of oil, NGLs and natural gas; and ● the judgment of the persons preparing the estimates.
Investors should not assume that PV-10, or PV-10 before ARO, of our proved oil and natural gas reserves shown above represent a current market value of our estimated oil and natural gas reserves.
Investors should not assume that PV-10, or PV-10 before ARO, of our proved oil and natural gas reserves shown below represent a current market value of our estimated oil and natural gas reserves.
Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment.
Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and 33 Table of Contents geological interpretation and judgment.
PV-10 and PV-10 before ARO should not be considered in isolation or as substitutes for the standardized measure of discounted future net cash flows as defined under GAAP.
PV-10 and PV-10 before ARO should not be considered in isolation or as substitutes for the standardized measure of discounted future net 34 Table of Contents cash flows as defined under GAAP.
See Proved Undeveloped Reserves below for a table reconciling the change in PUDs during 2024. See Financial Statements and Supplementary Data – Note 18 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for additional information.
See Proved Undeveloped Reserves below for a table reconciling the change in PUDs during 2025. See Financial Statements and Supplementary Data – Note 17 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for additional information.
Future production and development costs are based on year-end costs with no escalation. Reconciliation of Standardized Measure to PV-10 Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.
Future production and development costs are based on year-end costs with no escalation. Reconciliation of PV-10 to Standardized Measure of Discounted Future Net Cash Flows Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.
Our Director of Reservoir Engineering has over 35 years of oil and gas industry experience and has managed the preparation of public company reserve estimates the last 21 years. He joined the Company in 2016 after spending the preceding 12 years as Director of Corporate Engineering for Freeport-McMoRan Oil & Gas.
Our Director of Reservoir Engineering has over 36 years of oil and gas 36 Table of Contents industry experience and has managed the preparation of public company reserve estimates the last 22 years. He joined the Company in 2016 after spending the preceding 12 years as Director of Corporate Engineering for Freeport-McMoRan Oil & Gas.
At December 31, 2024, our proved reserves had a standardized measure of discounted future net cash flows of $740.1 million and a present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum (“PV-10”) of $1,229.5 million.
At December 31, 2025, our proved reserves had a standardized measure of discounted future net cash flows of $651.3 million and a present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum (“PV-10”) of $1,115.3 million.
The primary exceptions are at the Mississippi Canyon 243 field (“Matterhorn”), Ship Shoal 349 field (“Mahogany”) and 36 Table of Contents Viosca Knoll 823 field (“Virgo”) where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability.
The primary exceptions to the five-year rule are at the Ship Shoal 349 field (“Mahogany”) and the Viosca Knoll 823 field (“Virgo”) where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability.
The following table presents our estimates as to the timing of converting our PUDs to proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ Percentage of ​ ​ ​ ​ PUD Reserves ​ ​ Number of PUD ​ Scheduled to be Year Scheduled for Development ​ Locations ​ Developed 2025 — ​ — % 2026 12 ​ 79 % 2027 ​ 2 ​ 18 % 2028 — ​ — % 2029+ 1 ​ 3 % Total 15 100 % ​ As of December 31, 2024, we believe that we will be able to develop all but 5.9 MMBoe (approximately 27%) of the total 21.7 MMBoe classified as PUDs within five years from the date such PUDs were initially recorded.
The following table presents our estimates as to the timing of converting our PUDs to proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Percentage of ​ ​ ​ ​ PUD Reserves ​ ​ Number of PUD ​ Scheduled to be Year Scheduled for Development ​ Locations ​ Developed 2026 2 ​ 51 % 2027 1 ​ 7 % 2028 ​ 3 ​ 32 % 2029 — ​ — % 2030+ 1 ​ 10 % Total 7 100 % ​ As of December 31, 2025, we believe that we will be able to develop 2.6 MMBoe (approximately 40% of the total 6.7 MMBoe classified as PUDs) within five years from the date such PUDs were initially recorded.
Our estimates of proved reserves are based on the quantities of oil, NGLs and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. 33 Table of Contents In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, historical price and cost information, and property ownership interests.
Our estimates of proved reserves are based on the quantities of oil, NGLs and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate.
The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
The 10% discount factor, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
The following table presents the timing of expiration of our undeveloped leasehold acreage: ​ ​ ​ ​ ​ ​ ​ Undeveloped Acreage ​ Net Percent of Total 2025 8,813 30% 2026 — 0% 2027 ​ 10,760 ​ 36% 2028 ​ 10,000 ​ 34% Thereafter ​ — ​ 0% Total 29,573 100% ​ ​ ​ ​ ​ In making decisions regarding drilling and operations activity for 2025 and beyond, we give consideration to undeveloped leasehold interests that may expire in the near term in order that we might retain the opportunity to extend such acreage.
We have the right to propose future exploration and development projects on the majority of our acreage. 37 Table of Contents The following table presents the timing of expiration of our undeveloped leasehold acreage: ​ ​ ​ ​ ​ ​ ​ Undeveloped Acreage ​ ​ ​ ​ Net ​ ​ ​ Percent of Total 2026 — 0% 2027 14,573 74% 2028 ​ 5,000 ​ 26% 2029 ​ — ​ 0% Thereafter ​ — ​ 0% Total 19,573 100% ​ ​ ​ ​ ​ In making decisions regarding drilling and operations activity for 2025 and beyond, we give consideration to undeveloped leasehold interests that may expire in the near term in order that we might retain the opportunity to extend such acreage.
Future income tax expenses are calculated by applying the year-end statutory tax rates to the pre-tax net cash flows. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate.
Future income tax expenses are calculated by applying the year-end statutory tax rates to the pre-tax net cash flows. The standardized measure of discounted future net cash flows shown should not be construed as the current market value of the reserves.
The following table presents our estimated net proved reserves at December 31, 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ NGLs ​ Natural ​ ​ ​ PV-10 ​ ​ (MMBbls) ​ (MMBbls) ​ Gas (Bcf) ​ MMBoe ​ (in millions) Proved developed producing 19.5 ​ 8.2 ​ 229.4 ​ 66.0 $ 549.8 Proved developed non-producing 17.5 ​ 4.0 ​ 106.6 ​ 39.3 520.7 Total proved developed 37.0 12.2 336.0 105.3 1,070.5 Proved undeveloped 14.6 ​ 0.8 ​ 38.4 ​ 21.7 159.0 Total proved 51.6 13.0 374.4 127.0 $ 1,229.5 In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2024 were calculated using the WTI oil average spot price of $76.32 per barrel and the Henry Hub natural gas average spot price of $2.13 per MMBtu as the referenced price and, after adjusting for quality, transportation, fees, energy content and regional price differences, the adjusted average product prices were $74.69 per barrel for oil, $22.98 per barrel for NGLs and $2.58 per Mcf for natural gas.
The following table presents our estimated net proved reserves at December 31, 2025: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ NGLs ​ Natural ​ ​ ​ PV-10 ​ ​ (MMBbls) ​ (MMBbls) ​ Gas (Bcf) ​ MMBoe ​ (in millions) Proved developed producing 22.5 ​ 8.9 ​ 325.1 ​ 85.5 $ 829.2 Proved developed non-producing 10.4 ​ 2.7 ​ 93.8 ​ 28.8 244.3 Total proved developed 32.9 11.6 418.9 114.3 1,073.5 Proved undeveloped 5.8 ​ 0.1 ​ 4.4 ​ 6.7 41.8 Total proved 38.7 11.7 423.3 121.0 $ 1,115.3 In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2025 were calculated using the WTI oil average spot price of $66.01 per barrel and the Henry Hub natural gas average spot price of $3.39 per MMBtu as the referenced price and, after adjusting for quality, transportation, fees, energy content and regional price differences, the adjusted average product prices were $64.97 per barrel for oil, $19.67 per barrel for NGLs and $3.88 per Mcf for natural gas.
PV–10 is a computation of the standardized measure of discounted future net cash flows on a pre–tax basis and is computed on the same basis as standardized measure but does not include a provision for federal income taxes, Texas gross margin tax or other state taxes. 34 Table of Contents Neither PV-10 nor PV-10 before ARO are financial measures defined under accounting principles generally accepted in the United States of America (“GAAP”); therefore, the following table reconciles these amounts to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.
Neither PV-10 nor PV-10 before ARO are financial measures defined under accounting principles generally accepted in the United States of America (“GAAP”); therefore, the following table reconciles these amounts to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.
The following table presents changes in our PUDs (in MMBoe): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ 2024 2023 2022 PUDs, beginning of year 19.7 20.5 20.6 Revisions of previous estimates 0.8 (1.3) (0.1) Purchase of minerals in place 1.2 0.5 — PUDs, end of year 21.7 19.7 20.5 ​ ​ ​ ​ ​ The revisions of previous estimates were due to changes in SEC pricing.
The following table presents changes in our PUDs (in MMBoe): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 ​ ​ ​ 2023 PUDs, beginning of year 21.7 19.7 20.5 Revisions of previous estimates (15.0) 0.8 (1.3) Purchase of minerals in place — 1.2 0.5 PUDs, end of year 6.7 21.7 19.7 ​ ​ ​ ​ ​ 35 Table of Contents The revisions of previous estimates were primarily due to PUD locations becoming uneconomic under current conditions (5.7 MMBoe) and PUD locations being dropped in compliance with the SEC’s five-year rule (9.2 MMBoe).
Based on the latest reserve report, these PUD locations are expected to be developed in 2026 and 2036. The other exception is at the Garden Banks 783 field (“Magnolia”) where significant spending has already begun on rig and platform modifications for development drilling, but the timeline has been extended to 2026 before we will be able to mobilize the rig.
The other exception is at the Garden Banks 783 field where significant spending has already begun on rig and platform modifications for development drilling, but the timeline has been extended to 2026 before we will be able to mobilize the rig. Future development costs associated with our PUDs at December 31, 2025 were estimated at $198.4 million.
Gross wells are the total number of productive wells in which we have a working interest, regardless of our percentage interest. A net well is not a physical 38 Table of Contents well but is a concept that reflects actual working interest we hold in a given well. Our wells may produce both oil and natural gas.
A net well is not a physical well but is a concept that reflects actual working interest we hold in a given well. Our wells may produce both oil and natural gas. We classify a well as an oil well if the net equivalent production of oil was greater than natural gas for the well.
The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil Wells (1) ​ Gas Wells (2) ​ Total Wells ​ Gross Net Gross Net Gross Net Operated 163.0 ​ 154.4 ​ 97.0 ​ 87.8 ​ 260.0 ​ 242.2 Non-operated 34.0 ​ 5.8 ​ 8.0 ​ 2.7 ​ 42.0 ​ 8.5 Total 197.0 160.2 105.0 90.5 302.0 250.7 ​ ​ (1) Includes 17 gross (16.0 net) oil wells with multiple completions.
The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2025: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil Wells (1) ​ Gas Wells (2) ​ Total Wells ​ ​ ​ ​ Gross ​ ​ ​ Net ​ ​ ​ Gross ​ ​ ​ Net ​ ​ ​ Gross ​ ​ ​ Net Operated 173.0 ​ 164.8 ​ 95.0 ​ 88.3 ​ 268.0 ​ 253.1 Non-operated 36.0 ​ 6.3 ​ 5.0 ​ 1.3 ​ 41.0 ​ 7.6 Total 209.0 171.1 100.0 89.6 309.0 260.7 ​ ​ (1) Includes 21 gross (19.9 net) oil wells with multiple completions.
Drilling Activity We did not complete any wells during 2024 and 2023. During 2022, we completed two gross (0.6 net) exploratory wells, of which one gross (0.3 net) well is currently producing. Productive Wells Productive wells consist of producing wells and wells capable of production.
Drilling Activity We did not complete any wells during 2025, 2024 and 2023. Productive Wells Productive wells consist of producing wells and wells capable of production. Gross wells are the total number of productive wells in which we have a working interest, regardless of our percentage interest.
Three sidetrack PUD locations, one each at Matterhorn, Mahogany and Virgo, will be delayed until an existing well is depleted and available to sidetrack. We also plan to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of the existing well.
Two sidetrack PUD locations, one each at Mahogany and Virgo, will be delayed until an existing well is depleted and available to sidetrack. Based on the latest reserve report, these PUD locations are expected to be developed in 2038 and 2026, respectively.
Developed and Undeveloped Acreage The following table summarizes our developed and undeveloped acreage at December 31, 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Acreage ​ Undeveloped Acreage ​ Total Acreage ​ Gross Net Gross Net Gross Net Shelf 469,158 ​ 413,460 ​ 23,813 ​ 23,813 492,971 437,273 Deepwater 141,929 ​ 56,540 ​ 5,760 ​ 5,760 147,689 62,300 Alabama State Waters ​ 5,553 ​ 2,716 ​ — ​ — ​ 5,553 ​ 2,716 Total 616,640 472,716 29,573 29,573 646,213 502,289 ​ ​ ​ Our net acreage increased 62,258 net acres (14%) from December 31, 2023 due to leases acquired in the January 2024 acquisition offset by lease expirations.
Developed and Undeveloped Acreage The following table summarizes our developed and undeveloped acreage at December 31, 2025: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Acreage ​ Undeveloped Acreage ​ Total Acreage ​ ​ ​ ​ Gross ​ ​ ​ Net ​ ​ ​ Gross ​ ​ ​ Net ​ ​ ​ Gross ​ ​ ​ Net Shelf 463,398 ​ 413,930 ​ 13,813 ​ 13,813 477,211 427,743 Deepwater 136,169 ​ 54,020 ​ 5,760 ​ 5,760 141,929 59,780 Alabama State Waters ​ 5,553 ​ 2,716 ​ — ​ — ​ 5,553 ​ 2,716 Total 605,120 470,666 19,573 19,573 624,693 490,239 ​ ​ ​ Our net acreage decreased 12,050 net acres (2%) from December 31, 2024 due to lease expirations.
Removed
Future development costs associated with our PUDs at December 31, 2024 were estimated at $659.8 million.
Added
In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, historical price and cost information, and property ownership interests.
Removed
Approximately 94.1% of our net acreage is held by production. We have the right to propose future exploration and development projects on the majority of our acreage.
Added
PV–10 is a computation of the standardized measure of discounted future net cash flows on a pre–tax basis and is computed on the same basis as standardized measure of discounted future net cash flows but does not include a provision for ARO, federal income taxes, Texas gross margin tax or other state taxes.
Removed
We classify a well as an oil well if the net equivalent production of oil was greater than natural gas for the well.
Added
This rule requires oil and natural gas companies to classify undeveloped reserves as “proved” if the development plan for the reserves provides for drilling within five years of being booked. Reserves that remain undeveloped for more than five years from the date they were booked may still be classified as PUDs, but only if it is justified by specific circumstances.
Removed
(2) Includes 3 gross (2.6 net) natural gas wells with multiple completions. Production Data See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations under Part II, Item 7 in this Form 10-K for additional information. ​ ​
Added
Approximately 96.0% of our net acreage is held by production.
Added
(2) Includes 5 gross (4.3 net) natural gas wells with multiple completions. 38 Table of Contents Production Data The following table presents information relating to our production volumes, average realized sales prices and average production costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 ​ ​ ​ 2023 Production volumes: ​ ​ ​ ​ ​ ​ Oil (MBbls) ​ 5,115 ​ 5,255 ​ 5,050 NGLs (MBbls) ​ 1,139 ​ 1,212 ​ 1,415 Natural gas (MMcf) ​ 36,890 ​ 34,296 ​ 37,591 Total oil equivalent (MBoe) ​ 12,402 ​ 12,183 ​ 12,730 Average realized sales prices: ​ ​ ​ ​ ​ ​ Oil ($/Bbl) ​ $ 64.09 ​ $ 75.28 ​ $ 75.52 NGLs ($/Bbl) ​ 17.88 ​ 23.08 ​ 22.93 Natural gas ($/Mcf) ​ 3.90 ​ 2.65 ​ 2.93 Oil equivalent ($/Boe) ​ 39.68 ​ 42.23 ​ 41.16 Average production costs: (1) ​ ​ ​ ​ ​ ​ Oil equivalent ($/Boe) ​ $ 26.17 ​ $ 25.41 ​ $ 22.30 ​ ​ (1) Includes lease operating expenses and gathering, transportation and production taxes. ​ ​

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeITEM 3. LEGAL PROCEEDINGS See Financial Statements and Supplementary Data – Note 6 – Commitments and Contingencies under Part II, Item 8 in this Form 10-K for information on various legal proceedings to which we are party or our properties are subject. ​ ITEM 4. MINE SAFETY DISCLOSURES Not applicable. ​ 39 Table of Contents PART II
Biggest changeITEM 3. LEGAL PROCEEDINGS See Financial Statements and Supplementary Data – Note 5 – Commitments and Contingencies under Part II, Item 8 in this Form 10-K for information on various legal proceedings to which we are party or our properties are subject. ​ ITEM 4. MINE SAFETY DISCLOSURES Not applicable. PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeDividends On March 3, 2025, our board of directors declared a quarterly cash dividend of $0.01 per share of common stock, or approximately $1.5 million, to be paid on March 24, 2025 to shareholders of record at the close of business on March 17, 2025.
Biggest changeDividends On March 5, 2026, our board of directors declared a quarterly cash dividend of $0.01 per share of common stock to be paid on March 26, 2026 to shareholders of record at the close of business on March 19, 2026.
The information contained in the graph below is furnished and not filed and is not incorporated by reference into any document that incorporates this Form 10-K by reference. ​ 40 Table of Contents Equity Compensation Plan Information For equity compensation plan information, refer to Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters under Part III, Item 12 in this Annual Report on Form 10-K.
The information contained in the graph below is furnished and not filed and is not incorporated by reference into any document that incorporates this Form 10-K by reference. 39 Table of Contents ​ Equity Compensation Plan Information For equity compensation plan information, refer to Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters under Part III, Item 12 in this Annual Report on Form 10-K.
Stock Performance Graph The performance graph below shows the cumulative total shareholder return on our common stock compared with the S&P Oil and Gas Exploration and S&P 500 indices over the five-year period beginning on December 31, 2019.
Stock Performance Graph The performance graph below shows the cumulative total shareholder return on our common stock compared with the S&P Oil and Gas Exploration and S&P 500 indices over the five-year period beginning on December 31, 2020.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock is listed and principally traded on the NYSE under the symbol “WTI.” As of March 1, 2025, there were 127 registered holders of our common stock.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock is listed and principally traded on the NYSE under the symbol “WTI.” As of February 28, 2026, there were 124 registered holders of our common stock.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeOur oil, NGL and natural gas revenues do not include the effects of derivatives, which are reported in Derivative (gain) loss, net in our Consolidated Statements of Operations. 45 Table of Contents The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for 2024 and 2023 (in thousands, except average realized sales prices data): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ ​ 2024 2023 ​ Change Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ $ 395,620 ​ $ 381,389 ​ $ 14,231 NGLs ​ 27,978 ​ 32,446 ​ (4,468) Natural gas ​ 90,877 ​ 110,158 ​ (19,281) Other ​ 10,786 ​ 8,663 ​ 2,123 Total revenues ​ $ 525,261 ​ $ 532,656 ​ $ (7,395) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production Volumes: ​ ​ ​ Oil (MBbls) ​ 5,255 ​ 5,050 ​ 205 NGLs (MBbls) ​ 1,212 ​ 1,415 ​ (203) Natural gas (MMcf) ​ 34,296 ​ 37,591 ​ (3,295) Total oil equivalent (MBoe) ​ 12,183 ​ ​ 12,730 ​ ​ (547) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily equivalent sales (Boe/day) ​ ​ 33,287 ​ ​ 34,877 ​ ​ (1,590) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized sales prices: ​ ​ ​ ​ ​ ​ ​ ​ Oil ($/Bbl) ​ $ 75.28 ​ $ 75.52 ​ $ (0.24) NGLs ($/Bbl) ​ 23.08 ​ 22.93 ​ 0.15 Natural gas ($/Mcf) ​ 2.65 ​ 2.93 ​ (0.28) Oil equivalent ($/Boe) ​ ​ 42.23 ​ ​ 41.16 ​ ​ 1.07 Oil equivalent ($/Boe), including realized commodity derivatives ​ 42.47 ​ 40.84 ​ 1.63 ​ ​ 46 Table of Contents Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between 2024 and 2023 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Price Volume ​ Total Oil $ (1,208) ​ $ 15,439 ​ $ 14,231 NGLs 172 ​ ​ (4,640) ​ (4,468) Natural gas (9,626) ​ ​ (9,655) ​ (19,281) ​ $ (10,662) ​ $ 1,144 ​ $ (9,518) ​ Production volumes decreased by 547 MBoe to 12,183 MBoe during 2024 compared to the same period in 2023, primarily due to deferred production of approximately 0.8 MMBoe at our Mobile Bay Properties, approximately 0.3 MMBoe from the shut-on of the MP 98 and 108 fields and approximately 0.2 MMBoe from the effects of Hurricanes Francine, Helene and Rafael .
Biggest changeOur oil, NGL and natural gas revenues do not include the effects of derivatives, which are reported in Derivative gain, net in our Consolidated Statements of Operations. 44 Table of Contents The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for 2025 and 2024 (in thousands, except average realized sales prices data): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ ​ 2025 ​ ​ ​ 2024 ​ ​ ​ ​ Change Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ $ 327,845 ​ $ 395,620 ​ $ (67,775) NGLs ​ 20,371 ​ 27,978 ​ (7,607) Natural gas ​ 143,948 ​ 90,877 ​ 53,071 Other ​ 9,298 ​ 10,786 ​ (1,488) Total revenues ​ $ 501,462 ​ $ 525,261 ​ $ (23,799) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production Volumes: ​ ​ ​ ​ ​ ​ Oil (MBbls) ​ 5,115 ​ 5,255 ​ (140) NGLs (MBbls) ​ 1,139 ​ 1,212 ​ (73) Natural gas (MMcf) ​ 36,890 ​ 34,296 ​ 2,594 Total oil equivalent (MBoe) ​ 12,402 ​ ​ 12,183 ​ ​ 219 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily equivalent sales (Boe/day) ​ ​ 33,978 ​ ​ 33,287 ​ ​ 691 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized sales prices: ​ ​ ​ ​ ​ ​ ​ ​ Oil ($/Bbl) ​ $ 64.09 ​ $ 75.28 ​ $ (11.19) NGLs ($/Bbl) ​ 17.88 ​ 23.08 ​ (5.20) Natural gas ($/Mcf) ​ 3.90 ​ 2.65 ​ 1.25 Oil equivalent ($/Boe) ​ ​ 39.68 ​ ​ 42.23 ​ ​ (2.55) Oil equivalent ($/Boe), including realized commodity derivatives ​ 41.00 ​ 42.47 ​ (1.47) ​ Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between 2025 and 2024 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Price ​ ​ ​ Volume ​ Total Oil $ (57,231) ​ $ (10,544) ​ $ (67,775) NGLs (5,918) ​ ​ (1,689) ​ (7,607) Natural gas 46,197 ​ ​ 6,874 ​ 53,071 ​ $ (16,952) ​ $ (5,359) ​ $ (22,311) ​ Production volumes increased by 219 MBoe to 12,402 MBoe during 2025 compared to the same period in 2024, primarily due to restoring production at our West Delta 73, MO 916 and Main Pass 108 fields and increased production at our Mobile Bay fields due to well stimulation work and reduced downtime, partially offset by unplanned third party pipeline outages and the shut-in of a well due to solids production . 45 Table of Contents Operating Expenses The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ ​ ​ ​ 2025 ​ ​ ​ 2024 ​ ​ ​ ​ Change Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating expenses ​ $ 298,781 ​ $ 281,488 ​ $ 17,293 Gathering, transportation and production taxes ​ ​ 25,743 ​ ​ 28,177 ​ ​ (2,434) Depreciation, depletion and amortization ​ 116,405 ​ ​ 143,025 ​ (26,620) Asset retirement obligations accretion ​ 33,381 ​ ​ 32,374 ​ 1,007 General and administrative expenses ​ ​ 79,955 ​ ​ 82,391 ​ ​ (2,436) Total operating expenses ​ $ 554,265 ​ $ 567,455 ​ $ (13,190) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average per Boe ($/Boe): ​ ​ ​ ​ ​ ​ Lease operating expenses ​ $ 24.09 ​ $ 23.10 ​ $ 0.99 Gathering, transportation and production taxes ​ 2.08 ​ 2.31 ​ (0.23) Depreciation, depletion and amortization ​ 9.39 ​ 11.74 ​ (2.35) Asset retirement obligations accretion ​ ​ 2.69 ​ ​ 2.66 ​ ​ 0.03 General and administrative expenses ​ 6.45 ​ 6.76 ​ (0.31) Total operating expenses ​ $ 44.70 ​ $ 46.57 ​ $ (1.87) ​ Lease operating expenses Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America.
Bonding In prior years, some of the sureties, which provided us surety bonds that we use for supplemental financial assurance purposes, requested and received collateral from us. Pursuant to the terms of our agreement with various sureties under out existing bonding arrangements, we may be required to post collateral.
Bonding In prior years, some of the sureties, which provided us surety bonds that we use for supplemental financial assurance purposes, requested and received collateral from us. Pursuant to the terms of our agreement with various sureties under our existing bonding arrangements, we may be required to post collateral.
See Financial Statements and Supplementary Data – Note 10 – Leases under Part II, Item 8 in this 10-K for information regarding scheduled maturities of our operating leases.
See Financial Statements and Supplementary Data – Note 9 – Leases under Part II, Item 8 in this 10-K for information regarding scheduled maturities of our operating leases.
Additionally, a 10% reduction in PV-10 at December 31, 2024, while all other factors remained constant, would also not have generated an impairment. The policies discussed above impact the carrying value of our properties and involve significant judgments about the impact of future events on our estimated cash flows.
Additionally, a 10% reduction in PV-10 at December 31, 2025, while all other factors remained constant, would also not have generated an impairment. The policies discussed above impact the carrying value of our properties and involve significant judgments about the impact of future events on our estimated cash flows.
Discussions of 2023 items and comparisons between 2023 and 2022 that are not included in this Form 10-K are incorporated by reference to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2023.
Discussions of 2024 items and comparisons between 2024 and 2023 that are not included in this Form 10-K are incorporated by reference to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2024.
If our assumptions change and we determine that we will be able to realize these carryforwards, the tax benefits related to any reversal of the valuation allowance on deferred tax assets as of December 31, 2024 would be recognized as a reduction of income tax expense.
If our assumptions change and we determine that we will be able to realize these carryforwards, the tax benefits related to any reversal of the valuation allowance on deferred tax assets as of December 31, 2025 would be recognized as a reduction of income tax expense.
The future cost of compliance with respect to supplemental financial assurances, including the 44 Table of Contents obligations imposed on us, whether as current or predecessor lessee or grant holder in respect of BOEM’s final rule or any new, more stringent, rules related to supplemental financial assurances could materially and adversely affect our financial condition, cash flows, liquidity and results of operations.
The future cost of compliance with respect to supplemental financial assurances, including the obligations imposed on us, whether as current or predecessor lessee or grant holder in respect of BOEM’s final rule or any new, more stringent, rules related to supplemental financial assurances could materially and adversely affect our financial condition, cash flows, liquidity and results of operations.
To the extent future r evisions to these estimates impact the value of our abandonment liability, a corresponding adjustment is made to our oil and natural gas property balance. 54 Table of Contents Income Taxes Our income tax expense and deferred tax assets and liabilities reflect management’s best assessment of estimated current and future taxes to be paid.
To the extent future r evisions to these estimates impact the value of our abandonment liability, a corresponding adjustment is made to our oil and natural gas property balance. Income Taxes Our income tax expense and deferred tax assets and liabilities reflect management’s best assessment of estimated current and future taxes to be paid.
We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank and other borrowings, and expect to continue to do so in the future. 49 Table of Contents We expect to support our business requirements primarily with cash on hand and cash generated from operations.
We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank and other borrowings, and expect to continue to do so in the future. We expect to support our business requirements primarily with cash on hand and cash generated from operations.
Key Challenges and Uncertainties In addition to general market conditions and competition in the oil and natural gas industry, we believe the following represent the key challenges and uncertainties we will face in the future. 43 Table of Contents Commodity Prices A prolonged period of weak commodity prices may create uncertainties in our financial condition and results of operations.
Key Challenges and Uncertainties In addition to general market conditions and competition in the oil and natural gas industry, we believe the following represent the key challenges and uncertainties we will face in the future. Commodity Prices A prolonged period of weak commodity prices may create uncertainties in our financial condition and results of operations.
There are other items within our consolidated financial statements that require estimation and judgment, but they are not deemed critical as defined above. Accounting for Oil and Natural Gas Properties We account for our oil and natural gas operations using the full cost method of accounting.
There are other items within our consolidated financial statements that require estimation and judgment, but they are not deemed critical as defined above. 51 Table of Contents Accounting for Oil and Natural Gas Properties We account for our oil and natural gas operations using the full cost method of accounting.
Certain amounts included in our contractual obligations as of December 31, 2024 are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. See Financial Statements and Supplementary Data – Note 5 – Debt under Part II, Item 8 in this 10-K for information regarding scheduled maturities of our debt.
Certain amounts included in our contractual obligations as of December 31, 2025 are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. See Financial Statements and Supplementary Data – Note 4 – Debt under Part II, Item 8 in this 10-K for information regarding scheduled maturities of our debt.
Quantitative and Qualitative Disclosures About Market Risk and with Part 1I, Item 8. Financial Statements and Supplementary Data and other financial information appearing elsewhere in this 2024 Form 10-K. The following discussion and analysis includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements.
Quantitative and Qualitative Disclosures About Market Risk and with Part II, Item 8. Financial Statements and Supplementary Data and other financial information appearing elsewhere in this 2025 Form 10-K. The following discussion and analysis includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements.
Termination of Credit Agreement and Entry into New Credit Agreement On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we terminated our Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) and entered into the New Credit Agreement which provides us a revolving credit and letter of credit facility with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million.
Termination of Legacy Credit Agreement and Entry into Credit Agreement On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we terminated our Sixth Amended and Restated Credit Agreement (the “Legacy Credit Agreement”) and entered into the Credit Agreement which provides us a revolving credit and letter of credit facility with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million.
Our most significant accounting policies are discussed in Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K. We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements for the year ended December 31, 2024.
Our most significant accounting policies are discussed in Financial Statements and Supplementary Data – Note 1 – Basis of Presentation and Significant Accounting Policies under Part II, Item 8 in this Form 10-K. We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements for the year ended December 31, 2025.
Financial Statements and Supplementary Data – Note 7 – Stockholders’ Equity and Note 19 – Subsequent Events of this Annual Report. Contractual Obligations and Commitments Our material cash commitments from known contractual and other obligations consist primarily of obligations for debt and related interest, operating leases, ARO and other obligations as part of normal operations.
Financial Statements and Supplementary Data – Note 6 – Stockholders’ Equity and Note 18 – Subsequent Events of this Annual Report. Contractual Obligations and Commitments Our material cash commitments from known contractual and other obligations consist primarily of obligations for debt and related interest, operating leases, ARO and other obligations as part of normal operations.
We cannot guarantee that any such potential transaction would be completed on acceptable terms, if at all. Asset Retirement Obligations We have obligations to plug and abandon wells, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. During 2024, we paid $39.7 million related to these obligations.
We cannot guarantee that any such potential transaction would be completed on acceptable terms, if at all. Asset Retirement Obligations We have obligations to plug and abandon wells, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. During 2025, we paid $36.8 million related to these obligations.
Our ARO estimates as of December 31, 2024 and 2023 were $548.8 million and $498.8 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one-to-many years in the future, the timing and amount of actual expenditures could be substantially different than our estimates.
Our ARO estimates as of December 31, 2025 and 2024 were $561.9 million and $548.8 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one-to-many years in the future, the timing and amount of actual expenditures could be substantially different than our estimates.
Hurricane expenses consist of costs for minor repairs and restoring production, as well as evacuating employees and contractors incurred as a result of Hurricanes Francine, Helene and Rafael. Gathering, transportation and production taxes Gathering and transportation consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale.
Hurricane expenses consist of costs for minor repairs and restoring production, as well as evacuating employees and contractors incurred as a result of Hurricanes Francine, Helene and Rafael during 2024. 46 Table of Contents Gathering, transportation and production taxes Gathering and transportation consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale.
In January 2025, we received $58.5 million related to the settlement of claims related to the Mobile Bay plant turnaround in February 2023. During the turnaround, the MB 78-1 well was shut-in and did not return to production following completion of the planned maintenance.
Significant Developments Receipt of Insurance Proceeds In January 2025, we received $58.5 million related to the settlement of claims related to the Mobile Bay plant turnaround in February 2023. During the turnaround, the MB 78-1 well was shut-in and did not return to production following completion of the planned maintenance.
Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Part I, Item 1A. Risk Factors . This section primarily discusses 2024 and 2023 items and comparisons between 2024 and 2023.
Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Part I, Item 1A. Risk Factors . 40 Table of Contents This section primarily discusses 2025 and 2024 items and comparisons between 2025 and 2024.
Business Overview We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of America. As of December 31, 2024, we held working interests in 52 offshore producing fields in federal and state waters (which include 45 fields in federal waters and seven in state waters).
Business Overview We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of America. As of December 31, 2025, we held working interests in 49 offshore producing fields in federal and state waters (which include 42 fields in federal waters and seven in state waters).
As of December 31, 2024, we had obligations for estimated fees for surety bonds related to obligations under certain purchase and sale agreements and for supplemental bonding for plugging and abandonment of $6.7 million payable in the next twelve months and $80.3 million through the estimated timing of the plugging and abandonment obligation occurs.
As of December 31, 2025, we had obligations for estimated fees for surety bonds related to obligations under certain purchase and sale agreements and for supplemental bonding for plugging and abandonment of $7.1 million payable in the next twelve months and $88.1 million through the estimated timing of the plugging and abandonment obligation occurs.
The rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalation in future years except by contractual arrangements. Our reserve estimates are prepared by our reserve engineers and our independent petroleum consultant, NSAI .
The rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalation in future years except by contractual arrangements.
At December 31, 2024, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.09 per Mcfe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.10 per Mcfe.
At December 31, 2025, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.06 per Mcfe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.06 per Mcfe.
Our preliminary capital expenditure budget for 2025 has been established in the range of $34.0 million to $42.0 million, which excludes acquisitions. In our view of the outlook for 2025, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2025 and beyond while providing liquidity to make strategic acquisitions.
Our preliminary capital expenditure budget for 2026 has been established in the range of $19.5 million to $24.5 million, which excludes acquisitions. In our view of the outlook for 2026, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2026 and beyond while providing liquidity to make strategic acquisitions.
On a per Boe basis, lease operating expenses increased to $23.10 per Boe during 2024 compared to $20.24 per Boe during 2023. On a component basis, base lease operating expenses increased $30.2 million, facility maintenance expenses increased $7.9 million and hurricane repairs increased $1.0 million, These increases were partially offset by a decrease of $15.3 million in workover expenses.
On a per Boe basis, lease operating expenses increased to $24.09 per Boe during 2025 compared to $23.10 per Boe during 2024. On a component basis, base lease operating expenses increased $10.0 million, workover expenses increased $5.6 million and facility maintenance expenses increased $2.7 million. These increases were partially offset by a decrease of $1.0 million in hurricane repairs.
We believe that it is more likely than not that the benefit from certain of these carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance of $29.2 million on the deferred tax assets related to these carryforwards.
We believe that it is more likely than not that the benefit from certain of these carryforwards will not be realized. In recognition of this risk, we have provided a full 53 Table of Contents valuation allowance against the deferred tax assets related to these carryforwards.
Our lease operating costs, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased $23.8 million to $281.5 million in 2024 compared to $257.7 million in 2023.
Our lease operating costs, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased $17.3 million to $298.8 million in 2025 compared to $281.5 million in 2024.
The decrease in net (loss) income adjusted for certain non-cash items was primarily related to a $7.4 million decrease in revenues and increases in cash operating expenses, partially offset by a $13.5 million increase in derivative cash receipts.
The decrease in net loss adjusted for certain non-cash items was primarily related to a $23.8 million decrease in revenues and increases in cash operating expenses, partially offset by a $10.1 million increase in derivative cash receipts.
Income tax (benefit) expense Our effective tax rates for 2024 and 2023 were 10.3% and 54.0%, respectively. These rates differed from the federal statutory rate of 21% primarily due to the impact of state income taxes, non-deductible compensation and adjustments to the valuation allowance on our deferred tax assets.
Our effective tax rate for 2024 was 10.3% and differed from the federal statutory rate primarily due to the impact of state income taxes, non-deductible compensation and adjustments to the valuation allowance on our deferred tax assets.
In addition, our oil, NGLs and natural gas production can also be significantly affected by both planned and unplanned production downtime caused by events such as planned repairs and upgrades, third-party downtime associated with non-operated properties and the transportation, gathering or processing of production and weather events.
Deferred Production Our oil, NGLs and natural gas production can be significantly affected by both planned and unplanned production downtime caused by events such as planned repairs and upgrades, third-party downtime associated with non-operated properties and the transportation, gathering or processing of production and weather events. For 2025, we estimate deferred production was approximately 2.5 MMBoe.
In these instances, we are obligated to pay, according to our interest ownership, a portion of exploration and development costs, and operating costs, which potentially could be offset by our interest in future revenue from these non-operated properties.
We have obligations under joint interest arrangements related to commitments that have not yet been incurred. In these instances, we are obligated to pay, according to our interest ownership, a portion of exploration and development costs, and operating costs, which potentially could be offset by our interest in future revenue from these non-operated properties.
During 2024, the $3.6 million derivative gain consisted of $2.9 million of realized gains on settled contracts and $0.7 million of unrealized gain, net, from the increase in the fair value of the open contracts.
During 2024, the $3.6 million derivative gain consisted of $2.9 million of realized gains on settled contracts and $0.7 million of unrealized gain, net, from the increase in the fair value of the open contracts. Other expense, net During 2025, other expense, net, was $8.4 million, compared to $18.1 million for 2024.
Our reserve estimates are updated at least annually using geological and reserve data, as well as production performance data. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available.
Our reserve estimates are prepared by our reserve engineers and our independent petroleum consultant, NSAI . 52 Table of Contents Our reserve estimates are updated at least annually using geological and reserve data, as well as production performance data. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available.
We currently have under lease approximately 646,200 gross acres (502,300 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,500 gross acres in Alabama state waters, 493,000 gross acres on the conventional shelf and approximately 147,700 gross acres in the deepwater.
We currently have under lease approximately 624,700 gross acres (490,200 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,600 gross acres in Alabama state waters, 477,200 gross acres on the conventional shelf and approximately 141,900 gross acres in the deepwater.
As of December 31, 2024, we have federal net operating loss (“NOL”) carryforwards of $51.5 million that do not expire, state NOL carryforwards of $104.1 million that expire on various dates from 2026 through 2043 and interest expense limitation carryforwards that do not expire.
As of December 31, 2025, we have federal net operating loss (“NOL”) carryforwards of $87.1 million that do not expire, state NOL carryforwards of $108.8 million that expire on various dates from 2038 through 2040 and interest expense limitation carryforwards of $117.5 million that do not expire.
During 2024, we have paid cash dividends totaling approximately $6.0 million to holders of our common stock. The amount and frequency of future dividends is subject to the discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors. For additional information about our dividends, see Part II, Item 8.
The amount and frequency of future dividends is subject to the discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors. For additional information about our dividends, see Part II, Item 8.
Additionally, we have obligations related to estimates of minimum quantities obligations for certain pipeline contracts which were assumed in conjunction with the purchase of an interest in the Heidelberg field of $0.6 million in the next twelve months and $1.0 million through the term of the contracts. 52 Table of Contents We have obligations under joint interest arrangements related to commitments that have not yet been incurred.
Additionally, we have obligations related to estimates of minimum quantities obligations for certain pipeline contracts which were assumed in conjunction with the purchase of an interest in the Heidelberg field of $0.4 million in the next twelve months and $0.4 million through the term of the contracts.
As of December 31, 2024, we had $109.0 million of available cash on hand and $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million.
As of December 31, 2025, we had $140.6 million of available cash on hand and $43.9 million available under our Credit Agreement, based on a borrowing base of $50.0 million and $6.1 million of letters of credit outstanding.
Gathering and transportation fees increased during the first half of 2024 compared with the first half of 2023 primarily related to higher production volumes in the first quarter of 2024 and higher processing fees for our Mobile Bay production that had to be re-routed to a different processing plant due to the shut-in of our primary Mobile Bay processing plant.
Gathering, transportation and production taxes decreased to $25.7 million in 2025 compared to $28.2 million in 2024, primarily due to higher processing fees for our Mobile Bay production that had to be re-routed to a different processing plant due to the shut-in of our Mobile Bay processing plant during 2024.
The decrease in operating assets and liabilities is primarily related to lower accounts receivable balances due to decreased revenues partially offset by higher accounts payable and accrued liabilities balances in the current period. Investing activities – Net cash used in investing activities for 2024 increased $36.6 million compared to 2023.
The increase in operating assets and liabilities is primarily related to lower accounts receivable balances due to decreased revenues partially offset by higher accounts payable and accrued liabilities balances in the current period.
This was primarily due to decreases of $37.6 million in net (loss) income adjusted for certain non-cash items and $18.2 million from changes in operating assets and liabilities.
This was primarily due to an increase of $29.6 million from changes in operating assets and liabilities offset by a decrease of $11.9 million in net loss adjusted for certain non-cash items.
As of December 31, 2024, we had expected cash payments for estimated interest on our long-term debt of $10.1 million payable within the next twelve months and $10.2 million payable through the maturity dates of our long-term debt. We entered into a drilling contract during 2023.
As of December 31, 2025, we have expected cash payments for estimated interest on our long-term debt of $37.8 million payable within the next twelve months and $78.4 million payable through the maturity dates of our long-term debt.
This was primarily due to an increase of $53.3 million in acquisition of property interests, partially offset by a decrease of $4.5 million in investment in oil and natural gas properties and the purchase of the corporate aircraft during 2023. Financing activities – Net cash used in financing activities during 2024 decreased by $313.2 million compared to 2023.
This increase in cash flows and a $79.9 million decrease in acquisition of property interests was partially offset by an $11.3 million increase in investments in oil and natural gas properties . Financing activities Net cash used in financing activities during 2025 increased by $60.5 million compared to 2024.
Accretion expense increased to $32.4 million in 2024 compared to $29.0 million in 2023 primarily due to our acquisition in January 2024 and revisions to the estimates used in calculating the liability.
Accretion expense increased to $33.4 million in 2025 compared to $32.4 million in 2024 primarily due to the increase in our ARO liability as a result of revisions to the estimates used in calculating the liability.
In addition to commodity prices, our production rates, levels of proved reserves, future development costs, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. 53 Table of Contents Using the first-day-of-the-month average for the 12-months ended December 31, 2024 of the WTI oil spot price of $76.32 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2024 of the Henry Hub natural gas price of $2.13 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2024.
Using the first-day-of-the-month average for the 12-months ended December 31, 2025 of the WTI oil spot price of $66.01 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2025 of the Henry Hub natural gas price of $3.39 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2025.
The following table presents our investments in oil and gas properties and equipment for exploration, development, acquisitions and other leasehold costs (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2024 2023 Exploration and development ​ ​ ​ ​ ​ ​ Conventional shelf (1) ​ $ 17,755 ​ $ 14,464 Deepwater ​ ​ 7,650 ​ ​ 25,551 Acquisitions of interests ​ 80,635 ​ 27,384 Seismic and other ​ 8,150 ​ 1,263 Investments in oil and gas property/equipment – accrual basis ​ $ 114,190 ​ $ 68,662 ​ (1) Includes exploration and development capital expenditures in Alabama state waters.
Capital Expenditures The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors including the prices of oil, NGLs and natural gas, acquisition opportunities, liquidity and financing options and the results of our exploration and development activities. 49 Table of Contents The following table presents our investments in oil and gas properties and equipment for exploration, development, acquisitions and other leasehold costs (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ 2025 ​ ​ ​ 2024 Exploration and development ​ ​ ​ ​ ​ ​ Conventional shelf (1) ​ $ 47,030 ​ $ 17,755 Deepwater ​ ​ 6,015 ​ ​ 7,650 Acquisitions of interests ​ 711 ​ 80,635 Seismic and other ​ 1,658 ​ 8,150 Investments in oil and gas property/equipment – accrual basis ​ $ 55,414 ​ $ 114,190 ​ (1) Includes exploration and development capital expenditures in Alabama state waters.
Although the EIA is forecasting OPEC+ will increase production, they expect the group will produce less oil than stated in its most recent production target in an effort to avoid significant inventory builds.
Although the EIA is forecasting OPEC+ will increase production, they expect the group will produce less oil than stated in its most recent production target in an effort to avoid significant inventory builds. 42 Table of Contents The EIA expects the spot prices for Henry Hub natural gas to average $3.46 per MMBtu in 2026, down 2% from the 2025 average of $3.53 per MMBtu, and average $4.59 per MMBtu in 2027.
Risk Factors and Financial Statements and Supplementary Data – Note 4 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO. 51 Table of Contents Debt As of December 31, 2024, we have $399.1 million in aggregate principal amount of long-term debt outstanding, with $28.7 million in aggregate principal coming due over the next twelve months.
Debt As of December 31, 2025, we have $358.8 million in aggregate principal amount of long-term debt outstanding, with $8.8 million in aggregate principal amount coming due over the next twelve months. For additional information about our long-term debt, see Part II, Item 8.
In April 2024, BOEM released a final rule that changes the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements.
BOEM Matters The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities in the OCS. In April 2024, BOEM released a final rule that changed the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements.
Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. The decrease in workover expenses and the increase in facilities maintenance expenses were due to the timing and mix of projects undertaken.
The increases in workover expenses and facilities maintenance expenses were due to the timing and mix of projects undertaken.
See Financial Statements and Supplementary Data – Note 19 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information. 42 Table of Contents ​ Business Outlook Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production.
We expect to pay the dividend on March 26, 2026 to stockholders of record on March 19, 2026. ​ Business Outlook Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production.
DD&A increased $28.3 million for 2024 compared to 2023 primarily due to increases of $33.3 million from an increase in the depletion rate per Mcfe and $1.3 million for depreciation of other property and the corporate airplane acquired in May 2023, partially offset by $6.3 million from the decrease in production for 2024 compared with 2023.
DD&A decreased $26.6 million for 2025 compared to 2024 primarily due to $28.6 million from a decrease in the depletion rate per Mcfe offset by $2.0 million from the increase in production for 2025 compared with 2024. The DD&A rate decreased to $9.39 per Boe in 2025 from $11.74 per Boe in 2024.
The EIA forecasts that the spot price for WTI oil will average $70.33 per barrel in 2025, 8% less than 2024, and then continue to fall another 11% to $62.50 per barrel in 2026. The unwinding of OPEC+ production cuts and strong growth in oil production outside of OPEC+ results in global oil production growing in the EIA forecast.
The EIA forecasts that the spot price for WTI oil will average $52.25 per barrel in 2026, 20% less than the average price of $65.46 per barrel in 2025 and then average $50.33 per barrel in 2027.
The increase is primarily due to increases of (i) $4.0 million in payroll costs consisting of $1.8 million related to merit and headcount increases and a $2.2 million employee retention credit recorded in 2023, (ii) $2.8 million in non-recurring legal fees and (iii) $1.9 million in medical claims cost, partially offset by a $2.1 million decrease in short-term incentive compensation costs. 48 Table of Contents Other Income and Expense The following table presents the components of other income and expense for the periods presented and corresponding changes (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ 2024 2023 ​ Change Interest expense, net ​ $ 40,454 ​ $ 44,689 ​ $ (4,235) Derivative gain, net ​ (3,589) ​ ​ (54,759) ​ 51,170 Other expense, net ​ 18,071 ​ ​ 5,621 ​ 12,450 Income tax (benefit) expense ​ (9,985) ​ ​ 18,345 ​ (28,330) ​ Interest expense, net Interest expense, net of interest income, decreased $4.2 million for 2024 compared with 2023 primarily due to decreases of $7.9 million from the redemption in February 2023 of our 9.75% Senior Second Lien Notes due 2023 and $1.9 million from the lower outstanding principal balance of the Term Loan, partially offset by $2.8 million incurred on the 11.75% Notes issued in late January 2023 and a $2.6 million decrease in interest income.
Other Income and Expense The following table presents the components of other income and expense for the periods presented and corresponding changes (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ ​ ​ ​ 2025 ​ ​ ​ 2024 ​ ​ ​ ​ Change Interest expense, net ​ $ 36,495 ​ $ 40,454 ​ $ (3,959) Loss on extinguishment of debt ​ ​ 15,015 ​ ​ — ​ ​ 15,015 Derivative gain, net ​ (13,593) ​ ​ (3,589) ​ (10,004) Other expense, net ​ 8,415 ​ ​ 18,071 ​ (9,656) Income tax expense (benefit) ​ 50,927 ​ ​ (9,985) ​ 60,912 ​ Interest expense, net Interest expense, net of interest income, decreased $4.0 million for 2025 compared with 2024 primarily due to a decrease of $42.3 million from the redemption of the 11.75% Notes and the repayment of the Term Loan in late January 2025, partially offset by $37.3 million incurred on the 10.75% Notes issued in late January 2025. 47 Table of Contents Loss on extinguishment of debt During 2025, we recorded a loss on extinguishment of debt related to our January 2025 refinancing.
The DD&A rate increased to $11.74 per Boe in 2024 from $9.01 per Boe in 2023. The DD&A rate per Boe increased primarily as a result of a higher depreciable base due to our January 2024 acquisition, increases in capital expenditures, future development costs and capitalized ARO and lower proved reserves.
The DD&A rate per Boe decreased primarily as a result of decreases in future development costs and a lower depreciable base, partially offset by decreased proved reserves.
During 2023, the $54.8 million derivative gain consisted of $4.1 million of realized losses on settled contracts and $58.9 million of unrealized gain, net, from the increase in the fair value of the open contracts.
During 2025, the $13.6 million derivative gain consisted of $16.3 million of realized gains on settled contracts offset by a $2.7 million unrealized loss from the decrease in the fair value of the open contracts.
We continuously review our liquidity and capital resources. If market conditions were to change, for instance, due to uncertainty created by geopolitical events, a pandemic or a significant prolonged decline in oil and natural gas prices, and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be negatively impacted.
If market conditions were to change, for instance, due to uncertainty created by geopolitical events, a pandemic or a significant prolonged decline in oil and natural gas prices, and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be negatively impacted. 48 Table of Contents Cash Flow Information The following table summarizes cash flows provided by (used in) each type of activity for the following periods (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ ​ 2025 ​ 2024 ​ ​ Change Operating activities ​ $ 77,243 ​ $ 59,539 ​ $ 17,704 Investing activities ​ 21,861 ​ (118,177) ​ 140,038 Financing activities ​ (69,039) ​ (8,562) ​ (60,477) ​ Operating activities Our largest source of operating cash is collecting cash from customers and joint interest partners from sales of our products.
The EIA published its latest Short-Term Energy Outlook in January 2025 . The EIA expects downward oil price pressures over much of the next two years as they expect that global oil production will grow more than global oil demand.
The EIA published its latest Short-Term Energy Outlook in January 2026 . The EIA expects oil prices to decline in 2026, as global oil production exceeds global oil demand, causing inventories to rise.
Base lease operating expenses increased primarily due to increases of $37.5 million of expenses at the fields acquired in January 2024 and September 2023 partially offset by $6.1 million of reduced expenses from the abandonment work to shutdown certain of our fields. 47 Table of Contents Workover and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production.
Workover and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period.
The EIA expects wholesale natural gas prices to increase because growth in demand, led by liquified natural gas exports, will outpace production growth and keep inventories in the next two years at or below their previous five-year averages.
The EIA expects wholesale natural gas prices to increase due to growth in demand, led by expanding liquified natural gas exports, and more natural gas consumption in the electric power sector from growing demand for power in the commercial and industrial sectors.
Removed
Recent Developments Business and Operational Updates On January 16, 2024, we closed on our acquisition of rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of America, among other assets, for $77.3 million (including closing fees and other transaction costs). The acquisition was funded using cash on hand.
Added
The Credit Agreement matures on July 28, 2028. Appeal with the Office of Natural Resources Revenue On August 26, 2025, the United States District Court for the Eastern District of Louisiana issued a favorable order on the Company’s motion for summary judgment regarding the disallowance of allowable reduction of cash payments for royalties owed to the ONRR.
Removed
We also assumed the related 41 Table of Contents AROs associated with these assets. This transaction is described in more detail under Financial Statements and Supplementary Data – Note 2 – Acquisitions , under Part II, Item 8 of this Annual Report.
Added
On December 15, 2025 and December 16, 2025, the ONRR released the Company’s administrative appeal bonds. The Company remains in discussions with the ONRR regarding the related litigation bond and the amount, if any, to be refunded or credited to the Company.
Removed
In December 2024, we entered into a purchase and sale agreement to sell a non-core interest in the Garden Banks Blocks 385 and 386. The effective date of the sale was December 1, 2024, and the transaction closed on January 8, 2025 for approximately $11.9 million following customary purchase price adjustments.
Added
As a result of the order, the Company reversed its $5.3 million accrual related to this matter. 41 Table of Contents Bonding Disputes On June 14, 2025, we entered into the USSIC Settlement Agreement and, on June 15, 2025, we entered into the PIIC Settlement Agreement to dismiss all claims with the applicable parties related to the Sureties Litigation without prejudice.
Removed
Effective December 20, 2024, we entered into a resolution with the third-party pipeline operator at our West Delta 73 field. As a result of this resolution, we expect to restart production from the field in the second quarter of 2025. We originally acquired the West Delta 73 field in our January 2024 acquisition.
Added
Pursuant to the applicable Settlement Agreement, USSIC and PIIC agree that: (i) there will be no change to the 2024 premium rates paid by us or any of its affiliates, subsidiaries or joint venture entities, for any currently existing surety bond executed by USSIC or PIIC until after December 31, 2026, at the earliest, (ii) USSIC and PIIC withdraw all demands for collateral and agree not to request, demand, or otherwise insist on collateral, whether related to a surety bond or pursuant to the indemnity agreements, until after December 31, 2026, at the earliest; provided that such restriction shall not apply if (a) we do not pay premiums owed to USSIC or PIIC when due; (b) a claim is made by a third party against any bond issued by USSIC or PIIC to us or its affiliates or subsidiaries; (c) there is an initiation of an insolvency proceeding for us or any of its affiliates, subsidiaries or joint venture entities, whether voluntary or involuntary; (d) there is an uncured event of default under the indenture governing our second lien notes due 2029 that results in an acceleration, in whole or in part, of the indebtedness thereunder; or (e) we or our affiliates or subsidiaries initiate a lawsuit against USSIC or PIIC.
Removed
In June 2024, we received notice from BSEE that we would be required to cease production at our Main Pass 108 and 98 fields as the result of a shut-in of midstream infrastructure not owned by us.
Added
Each of the Settlement Agreements also provides that, in the event that we enter into an agreement to provide collateral to another party in settlement of the Sureties Litigation on bonds existing as of the date of the Settlement Agreement, we shall, on a pro rata basis, provide substantially similar collateral to USSIC or PIIC as it does to such other party.
Removed
On December 11, 2024, we entered into a purchase agreement and other arrangements with the trustee of the bankruptcy estate of Energy XXI GOM, LLC and Cox Operating L.L.C.
Added
The entry into the Settlement Agreements resulted in the withdrawal of approximately $94 million in collateral demands. On June 30, 2025, we announced that the presiding judge in the Sureties Litigation recommended denying the requests for preliminary injunction submitted by two surety providers. The preliminary injunction would have required us to immediately post $105 million of collateral.
Removed
(the “Cox Trustee”) to acquire the necessary midstream infrastructure, which is expected to allow us to return the Main Pass 108 and 98 fields to production in the second quarter of 2025.
Added
The recommendation would effectively nullify all current collateral requests related to the surety litigation by the surety providers and we will not be required to post collateral (if at all) until a determination on the merits of the Sureties Litigation with the remaining surety providers.
Removed
Following developments in connection with the acquisition of the midstream infrastructure, on February 25, 2025, we mutually terminated the purchase agreement with the Cox Trustee and entered into a new purchase agreement with the Cox Trustee including the midstream infrastructure and additional properties.
Added
All of the remaining parties to the Sureties Litigation previously agreed to mediate the case until the mediator declares an impasse. Mediation is no longer active as the mediator has declared an impasse with respect to the surety providers that did not enter into the Settlement Agreements.
Removed
The closing of the acquisitions contemplated by the purchase agreement and subsequent return to production are subject to our obtaining approval from the Bankruptcy Court for the Southern District of Texas, necessary governmental approvals and permits in connection with the acquisitions, in addition to customary closing conditions.
Added
We continue to evaluate potential avenues for resolution of the remaining related premium and collateral-related matters. First Quarter 2026 Dividend On March 5, 2026, we declared a first quarter dividend of $0.01 per share.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeThe following table summarizes the historical results of our hedging activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2024 ​ 2023 Natural Gas ($/Mcf) ​ ​ Average realized sales price, before the effects of derivative settlements ​ $ 2.65 ​ $ 2.93 Effects of realized commodity derivatives ​ 0.08 ​ (0.11) Average realized sales price, including realized commodity derivatives ​ $ 2.73 ​ $ 2.82 ​ 55 Table of Contents Interest Rate Risk As of December 31, 2024, our interest rate risk exposure is mitigated as of result of fixed interest rates on all our long-term debt outstanding.
Biggest changeThe following table summarizes the historical results of our hedging activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ December 31, ​ ​ 2025 ​ 2024 Oil ($/Bbl): ​ ​ ​ ​ Average realized sales price, before the effects of derivative settlements ​ $ 64.09 ​ $ 75.28 Effects of realized commodity derivatives ​ 0.14 ​ — Average realized sales price, including realized commodity derivatives ​ $ 64.23 ​ $ 75.28 ​ ​ ​ ​ ​ ​ ​ Natural Gas ($/Mcf) ​ ​ ​ ​ Average realized sales price, before the effects of derivative settlements ​ $ 3.90 ​ $ 2.65 Effects of realized commodity derivatives ​ 0.42 ​ 0.08 Average realized sales price, including realized commodity derivatives ​ $ 4.32 ​ $ 2.73 ​ Interest Rate Risk As of December 31, 2025, our interest rate risk exposure is mitigated as a result of fixed interest rates on all our long-term debt outstanding.
We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas production through the use of swaps, purchased calls and purchased puts.
We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production through the use of swaps, purchased calls and purchased puts.
Should we ever have amounts outstanding under our New Credit Agreement, we would be subject to some interest rate risk exposure, as our New Credit Agreement has a variable interest rate per annum, which, at our option, is equal to either (a) an adjusted rate based on the Secured Overnight Financing Rate (“SOFR”) plus an applicable margin that varies from 3.750% to 4.750% depending on the utilization of the New Credit Agreement or (b) a base rate plus an applicable margin that varies from 2.750% to 4.750%, such base rate calculated based on the highest of (i) the federal funds effective rate plus ½ of 1.0%, (ii) the U.S.
Should we ever have amounts outstanding under our Credit Agreement, we would be subject to some interest rate risk exposure, as our Credit Agreement has a variable interest rate per annum, which, at our option, is equal to either (a) an adjusted rate based on the Secured Overnight Financing Rate (“SOFR”) plus an applicable margin that varies from 3.75% to 4.75% depending on the utilization of the Credit Agreement or (b) a base rate plus an applicable margin that varies from 2.75% to 4.75%, such base rate calculated based on the highest of (i) the federal funds effective rate plus ½ of 1.0%, (ii) the U.S.
Prime Rate and (iii) an adjusted SOFR rate for a 1-month interest period plus 1.0%. We do not have any derivative contracts related to interest rates as of December 31, 2024. ​ 56 Table of Contents
Prime Rate and (iii) an adjusted SOFR rate for a 1-month interest period plus 1.0%. We do not have any derivative contracts related to interest rates as of December 31, 2025. ​ 54 Table of Contents
For example, assuming a 10% decline in our average realized oil, NGL and natural gas sales prices in 2024 and assuming no other items had changed, our revenue would have decreased by approximately $51.5 million in 2024. This amount would be representative of the effect on operating cash flows under these price change assumptions.
For example, assuming a 10% decline in our average realized oil, NGL and natural gas sales prices in 2025 and assuming no other items had changed, our revenue would have decreased by approximately $49.2 million in 2025. This amount would be representative of the effect on operating cash flows under these price change assumptions.

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