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What changed in W&T OFFSHORE INC's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of W&T OFFSHORE INC's 2023 and 2024 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 2024 report.

+488 added−495 removedSource: 10-K (2025-03-04) vs 10-K (2024-03-06)

Top changes in W&T OFFSHORE INC's 2024 10-K

488 paragraphs added · 495 removed · 259 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

52 edited+61 added−58 removed37 unchanged
Biggest changeIn addition, in November 2021, the United States signed the Global Methane Pledge, a pact that aims to reduce global methane emissions by at least 30% below 2020 levels by 2030.The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, the Glasgow Climate Pact and the COP28 agreement, or other international conventions cannot be predicted at this time.
Biggest changeThe impacts of these orders, pledges and agreements, and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement and subsequent climate conferences or other international conventions cannot be predicted at this time and it is unclear what additional initiatives may be adopted or implemented that may have a negative impact on our financial condition.
However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas.
However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place a portion of their anticipated winter requirements of natural gas into storage facilities.
The federal environmental laws and regulations applicable to us and our operations include, among others, the following: 3 Table of Contents ● 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 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 government cannot conduct offshore lease sales without the development and approval of a National Outer Continental Shelf Oil and Gas Leasing Program (an “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 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 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. Leasing.
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.
Given the commoditized nature of the products we produce and market and the location of our production in the Gulf of Mexico, we believe the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production, as we believe that replacement customers could be obtained in a relatively short period of time on terms, conditions, and pricing substantially similar to those currently existing.
Given the commoditized nature of the products we produce and market and the location of our production in the Gulf of America, we believe the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production, as we believe that replacement customers could be obtained in a relatively short period of time on terms, conditions, and pricing substantially similar to those currently existing.
The Gulf of Mexico 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 high-quality conventional asset base with low decline.
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 $12.5 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 region retentions ranging from $2.5 million to $15.0 million on the conventional shelf properties and $10.0 million on the deepwater properties.
Our workforce in Texas is primarily composed of our corporate employees, including our executive officers, drilling and production managers, technical engineers and administrative and support staff. Our employees in Alabama, Louisiana and the Gulf of Mexico are primarily composed of skilled labor who conduct our field operations and manage third-party personnel used in support of our field operations.
Our workforce in Texas is primarily composed of our corporate employees, including our executive officers, drilling and production managers, technical engineers and administrative and support staff. Our employees in Alabama, Louisiana and the Gulf of America are primarily composed of skilled labor who conduct our field operations and manage third-party personnel used in support of our field operations.
Our operations on federal oil and natural gas leases in the OCS waters of the Gulf of Mexico 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 U.S. Department of the Interior (the “DOI”).
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.
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.
Our general and excess liability policies, among others, 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 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.
Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which can require us to evacuate personnel and shut in production until a storm subsides.
Tropical storms and hurricanes occur in the Gulf of America during the summer and fall, which can require us to evacuate personnel and shut in production until a storm subsides.
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 Mexico, 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 10 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. Our HSE&R group is comprised of a Vice President, Environmental, Safety and Regulatory Managers and 12 staff personnel.
We grow in opportunistic ways as we manage our balance sheet prudently and reinvest free cash flow. Our existing portfolio of 169 structures (108 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 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 do not believe that the regulatory decisions or activities relating to interstate or intrastate oil, condensate or NGL pipelines will affect us in a way that materially differs from the way they affect other oil, condensate and NGL producers or marketers. Climate Change.
We do not believe that the regulatory decisions or activities relating to interstate or intrastate oil or NGL pipelines will affect us in a way that materially differs from the way they affect other oil and NGL producers or marketers.
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 2023 was 3.4%.
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.
We intend to execute the following elements of our business strategy in order to achieve our strategic goals: ● Exploiting existing and acquired properties to add additional reserves and production; ● Exploring for reserves on our extensive acreage holdings and in other areas of the Gulf of Mexico; ● Acquiring reserves with substantial upside potential and additional leasehold acreage complementary to our existing acreage position at attractive prices; ● Continuing to manage our balance sheet in a prudent manner and continuing our track record of financial flexibility in any commodity price environment; and ● Carrying 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 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.
The OCSLA, which is administered by the BOEM and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service.
The OCSLA, which is administered by the BOEM and the Federal Energy Regulatory Commission (the “FERC”), requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service.
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. Safety and Environmental metrics are incorporated into employee evaluations when determining compensation.
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.
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. The United States has experienced a rise in inflation since October 2021.
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.
We use advanced seismic and geoscience tools to execute successful drilling projects. In managing our business, we are focused on optimizing production and increasing reserves in a profitable and prudent manner, while managing cash flows to meet our obligations and investment needs.
In managing our business, we are focused on optimizing production and increasing reserves in a profitable and prudent manner, while managing cash flows to meet our obligations and investment needs.
The price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, condensate, NGLs and other products are regulated by the FERC.
The price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market.
Although the Federal Reserve has stated that they will begin reducing the benchmark rate in 2024, if inflation were to continue to rise, it is possible the Federal Reserve would continue to take action they deem necessary to bring inflation down and to ensure price stability, including further 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.
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.
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.
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.
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. 9 Table of Contents Inflation .
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.
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.
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.
In general, interstate oil, condensate and NGL pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. The FERC has established an indexing system for such transportation, which generally allows such pipelines to take an annual inflation-based rate increase.
Interstate transportation rates for oil, NGLs and natural gas are regulated by the FERC. In general, interstate oil, condensate, NGL and natural gas pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.
In 2023, approximately 41% of our revenues were received from BP Products North America and approximately 13% from Chevron-Texaco, with no other customer comprising greater than 10% of our 2023 revenues.
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.
These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. 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.
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
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. Our ability to succeed depends on recruiting and retaining top talent in the industry.
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.
Financial Statements and Supplementary Data —Note 17 — Commitments for more information on decommissioning and financial assurance requirements. Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation.
Regulation of Sales and Transportation of Oil, NGLs and Natural Gas Our sales of oil, NGLs and natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation.
We are committed to the safety, health and wellness of our employees. Our highest priorities are the safety of all personnel and protection of the environment. We actively promote the highest standards of safety behavior and environmental awareness and strive to meet or exceed all applicable local and natural regulations.
We actively promote the highest standards of safety behavior and environmental awareness and strive to meet or exceed all applicable local and natural regulations. To drive a culture of personnel safety in our operations, we operate under a comprehensive Safety and Environmental Management System (“SEMS”).
For the past four decades, we have developed significant technical expertise in finding and developing properties in the Gulf of Mexico with existing production which provide the best opportunity to achieve a rapid return on our invested capital. We have successfully discovered and produced properties on the conventional shelf and in the deepwater across the Gulf of Mexico.
Since our founding in 1983 by our Chairman and Chief Executive Officer, Tracy Krohn, we have developed significant technical expertise in finding and developing properties in the Gulf of America with existing production which provide the best opportunity to achieve a return on our invested capital.
We believe employees choose W&T in part due to our professional advancement opportunities, on the job training, engaging culture and competitive compensation and benefits. As part of our compensation philosophy, we believe we must offer and maintain market competitive total rewards programs in order to attract and retain superior talent.
Our ability to succeed depends on recruiting and retaining top talent in the industry. We believe employees choose W&T in part due to our professional advancement opportunities, on the job training, engaging culture and competitive compensation and benefits.
We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See Item 1A .
We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See Item 1A . Risk Factors contained herein for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters.
ITEM 1. BUSINESS W&T Offshore, Inc. is an independent oil and natural gas producer, active in the acquisition, exploration and development of oil and natural gas properties in the Gulf of Mexico.
ITEM 1. BUSINESS W&T Offshore, Inc. (“we,” “our” or “us”) is a publicly held Texas corporation. We are an independent oil and natural gas producer with substantially all our operations offshore in the Gulf of America. We are active in the acquisition, exploration and development of oil and natural gas properties. We operate in one reportable segment.
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 November 2021, the DOI released its report on federal oil and natural gas leasing and permitting practices.
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.
Business Strategy The Gulf of Mexico offers unique advantages, and we are uniquely positioned to create value with a diverse portfolio in valuable shelf, deep shelf and deepwater projects. Our diverse portfolio of operations in the Gulf of Mexico enables stacked pay development, attractive primary production, and recompletion opportunities.
Our acreage, well, production and reserves information are described in more detail under Part I, Item 2. Properties, in this Form 10-K. Business Strategy The Gulf of America offers unique advantages, and we are uniquely positioned to create value with a diverse portfolio in valuable shelf, deep shelf and deepwater projects.
The methane emissions charge imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026.
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.
Numerous proposals have been made at the international levels of government to monitor and limit emissions of GHG as well as to restrict or eliminate future emissions.
Additionally, 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.
These programs not only include base wages and incentives in support of our pay for performance culture, but also health and retirement benefits. We focus many programs on employee wellness. 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.
As part of our compensation philosophy, we believe we must offer and maintain market competitive total rewards programs in order to attract and retain superior talent. These programs not only include base wages and incentives in support of our pay for performance culture, but also health and retirement benefits. We focus many programs on employee wellness.
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. Seasonality and Inflation Seasonality. Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months.
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.
Our ability to acquire additional oil and natural gas properties, acquire additional leases and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties, finance investments and consummate transactions in a highly competitive environment. 2 Table of Contents Oil and Natural Gas Marketing and Delivery Commitments The market for our oil, NGL and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil, NGLs and natural gas; the proximity and capacity of natural gas pipelines and other transportation facilities; the demand for oil, NGLs and natural gas; the marketing of competitive fuels; and the effect of state and federal regulation.
As a smaller oil and natural gas company, however, we have greater flexibility in decision making, can adapt quicker to market changes, have the potential for higher profit margins on smaller projects and have the opportunity to develop innovative strategies without the constraints of large-scale operations. 2 Table of Contents Oil and Natural Gas Marketing and Delivery Commitments The market for our oil, NGL and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil, NGLs and natural gas; the proximity and capacity of natural gas pipelines and other transportation facilities; the demand for oil, NGLs and natural gas; the marketing of competitive fuels; and the effect of state and federal regulation.
District Court’s order vacating Lease Sale 257 and ruled the highest bidders would receive the leases auctioned in Lease Sale 257. 5 Table of Contents In August 2022, Congress passed the Inflation Reduction Act (the “IRA”), which required the BOEM to offer at least two million acres for oil and natural gas leasing in the OCS.
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.
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. Our reports filed with the SEC are available free of charge to the general public through our website at www.wtoffshore.com.
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.
To drive a culture of personnel safety in our operations, we operate under a comprehensive Safety and Environmental Management System (“SEMS”). Our 2023 total recordable incident rate for employees was 0.25, which is far below the industry average for the Gulf of Mexico from 2022 of 0.88.
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.
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. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction.
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.
The threat of climate change continues to attract considerable public, governmental and scientific attention in the United States.
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.
We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas companies and individual producers and operators. Many of these competitors are large, well-established companies that have financial and other resources substantially greater than ours and a greater ability to provide the extensive regulatory financial assurances required for offshore properties.
Many of these competitors are large, well-established companies that have financial and other resources substantially greater than ours.
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. The proposed OCS Program includes a maximum of three potential oil and natural gas lease sales in the Gulf of Mexico scheduled in 2025, 2027 and 2029. Decommissioning and financial assurance requirements .
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.
By operating within our free cash flow, we are able to improve liquidity and optimize our balance sheet. ● Manage environmental, social, and governance matters. With ultimate oversight by our board of directors, Environmental, Social & Governance (“ESG”) matters are an integral part of our day-to-day operations and are incorporated into the strategic decision-making process across our business.
By operating within our free cash flow, we are able to improve liquidity and optimize our balance sheet. ● Maintain safety, sustainability and corporate responsibility as key principles for operations across all areas of our business. We are focused on maintaining high standards of safety, environmental responsibility and corporate citizenship across all elements of our business.
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W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in 1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983. Since our founding in 1983 by our Chairman and CEO, Tracy Krohn, we have continually grown our footprint in the Gulf of Mexico through acquisitions, exploration and development.
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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.
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As of December 31, 2023 we held working interests in 53 offshore producing fields in federal and state waters. Our acreage, well, production and reserves information are described in more detail under Part I, Item 2. Properties, in this Form 10-K.
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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.
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Our working interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC (“A-I LLC”), Aquasition II LLC (“A-II LLC”), and W&T Energy VI, LLC, Delaware limited liability companies and through our proportionately consolidated interest in Monza Energy, LLC (“Monza”).
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Our diverse portfolio of operations in the Gulf of America enables stacked pay development, attractive primary production, and recompletion opportunities. We use advanced seismic and geoscience tools to execute successful drilling projects.
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We have established a managerial ESG Task Force composed of cross-functional management-level employees in Operations, Health, Safety, Environmental and Regulatory (“HSE&R”), Legal, Human Resources and Finance. This task force is responsible for overseeing and managing our ESG reporting initiatives and suggesting areas of focus to our executive management.
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We closely monitor safety performance and consistently take steps to improve our performance. We strive to execute our business plan while simultaneously minimizing our environmental footprint, including emissions, potential spills and other impacts.
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Executive management in turn reports on those activities to the ESG Committee of our board of directors. We strive to execute our business plan while simultaneously reducing our environmental footprint, including emissions, potential spills and other impacts. With respect to social priorities, we maintain a company-wide diversity training program and focus on promoting diversity and inclusion.
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Production from the Gulf of America continues to provide some of the lowest greenhouse gas (“GHG”) emissions intensity due to the nature of subsea wells and established offshore pipelines and we continue to strive to lower our GHG emissions. Finally, we aim to be a good corporate citizen in the regions and communities where we operate.
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Relating to governance, our fundamental policy is to conduct our business with honesty and integrity in accordance with high legal and ethical standards.
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Competition The oil and natural gas industry is highly competitive. We encounter strong competition from numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas companies and individual producers and operators, in acquiring oil and natural gas properties, contracting for drilling equipment and securing trained personnel.
Removed
In 2023, w e published our third annual ESG report highlighting our performance and initiatives across ESG categories for the period of 2020 to 2022, which is not incorporated into, and does not form a part of, this Form 10-K. Finally, ESG performance scores are a factor in determining compensation for all management-level employees.
Added
As a result, our competitors may be better able to withstand the financial pressures of significant declines in oil and natural gas prices, unsuccessful drill attempts, delays, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may have a greater ability to provide the extensive regulatory financial assurances required for offshore properties and to absorb the burdens from changes in applicable laws and regulations.
Removed
Competition The oil and natural gas industry is highly competitive. We also face increasing indirect competition from alternative energy sources, including wind, solar, and electric power. We currently operate in the Gulf of Mexico and compete for the acquisition of oil and natural gas properties and lease sales primarily on the basis of price for such properties.
Added
Seasonal Nature of Our Business Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months.
Removed
Risk Factors contained herein for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters. 4 Table of Contents 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.
Added
However, the annual inflation rate for January 2025 was 3.0%, an increase from the 2.9% in December 2024.
Removed
In January 2021, President Biden issued an executive order suspending new leasing activities for oil and natural gas exploration and production on federal lands and offshore waters pending review and reconsideration of federal oil and natural gas permitting and leasing practices.
Added
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%.
Removed
Lease Sale 257 was originally scheduled to be held in March 2021, but the decision to hold the sale was rescinded after the issuance of the executive order. After a group of states challenged the executive order and a federal judge required the DOI to stop the leasing pause, Lease Sale 257 was rescheduled and held in November 2021.
Added
The Summary of Economic Projections published by the Federal Reserve in December 2024 points to another 50 basis points of cuts in 2025.
Removed
In January 2022, the D.C. District Court vacated Lease Sale 257, ruling that it violated the National Environmental Policy Act. In August 2023, the D.C. Circuit Court of Appeals reversed the D.C.
Added
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.
Removed
The IRA required the DOI to move forward with Lease Sales 259 and 261 in the Gulf of Mexico. Lease Sale 259 was held in March 2023, and Lease Sale 261 was held in December 2023.
Added
Exploration and Production Statutes, rules and regulations affecting exploration and production are subject to extensive and continually changing regulations as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability.
Removed
The report included recommendations in respect to the offshore sector, including adjusting royalty rates to ensure that the full value of leased tracts are captured, strengthening financial assurance coverage amounts that are required by operators, and establishing “fitness to operate” criteria that companies would need to meet in respect of safety, environmental and financial responsibilities in order to operate in the OCS.
Added
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.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeOur leverage and debt service obligations could: ● increase our vulnerability to general adverse economic and industry conditions; ● limit our ability to fund future working capital requirements, capital expenditures and ARO, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets; ● limit our opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt obligations or to comply with any restrictive terms of our debt obligations; ● limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; ● limit or impair our ability to obtain additional financing or refinancing in the future or require us to seek alternative financing, which may be more restrictive or expensive; and ● place us at a competitive disadvantage compared to our competitors that have less debt. 21 Table of Contents Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Biggest changeOur level of indebtedness has important consequences on our operations, including: ● increasing our vulnerability to general adverse economic and industry conditions; ● limiting our ability to fund future working capital requirements, capital expenditures and ARO, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets; ● requiring that we dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt obligations, thereby reducing the availability of cash flow for funding future working capital requirements, capital expenditures and ARO obligations, engaging in future acquisitions or development activities or otherwise realizing the value of our assets; ● limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; ● limiting or impairing our ability to obtain additional financing or refinancing in the future or requiring us to seek alternative financing, which may be more restrictive or expensive; and ● placing us at a competitive disadvantage compared to our competitors that have less debt.
Currently OPA requires owners and operators of offshore oil production facilities to have ready access to between $35.0 million and $150.0 million, which amount is based on a worst case oil spill discharge volume demonstration that can be used to cover costs that could be incurred in responding to an oil spill at our facilities on the OCS.
Currently the OPA requires owners and operators of offshore oil production facilities to have ready access to between $35.0 million and $150.0 million, which amount is based on a worst case oil spill discharge volume demonstration that can be used to cover costs that could be incurred in responding to an oil spill at our facilities on the OCS.
Although we take 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. Similar to other companies, we have experienced cyber-attacks, although we have not suffered any material losses related to such attacks.
New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement could significantly increase our capital expenditures and operating costs or result in delays, limitations or cancelations to our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows.
New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement could significantly increase our capital expenditures and operating costs or could result in delays, limitations or cancelations to our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows.
In addition, our current ESG governance structure may not allow us to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve ESG-related strategies and goals. Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
In addition, our current ESG governance structure may not allow us to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve ESG-related strategies and goals. Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.
We may not realize all of the anticipated benefits from 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. This could lead to potential adverse short-term or long-term effects on our operating results.
If we fail to comply with the proposed 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.
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.
Compliance with any new or more stringent regulatory requirements or enforcement initiatives and existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives, could adversely affect or delay new drilling and ongoing development efforts.
Compliance with any added or more stringent regulatory requirements or enforcement initiatives and existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives, could adversely affect or delay new drilling and ongoing development efforts.
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.
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.
Such legislative changes have included, but have not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures.
Such proposed legislative changes have included, but have not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures.
Our operations are subject to U.S. federal, state, local and foreign environmental laws and regulations governing, among other things, the emission and discharge of pollutants into the environment, the generation, storage, handling, use and transportation of toxic and hazardous wastes and the health and safety of our employees.
Our operations are subject to U.S. federal, state and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the environment, the generation, storage, handling, use and transportation of toxic and hazardous wastes and the health and safety of our employees.
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.
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.
Our operations could be adversely impacted by security breaches, including cybersecurity breaches, which could affect the systems, processes and data needed to run our business. We rely on our information technology infrastructure and management information systems to operate and record aspects of our business.
Our operations could be adversely impacted by security breaches, including cybersecurity breaches, which could affect the systems, processes and data needed to run our business. We rely on our information technology (“IT”) infrastructure and management information systems to operate and record aspects of our business.
We have divested, as assignor, various leases, wells and facilities located in the Gulf of Mexico where the purchasers, as assignees, typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations.
We have divested, as assignor, various leases, wells and facilities located in the Gulf of America where the purchasers, as assignees, typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations.
Also, if material spill incidents were to occur in the future, the United States could elect to issue directives to temporarily cease drilling activities and, in any event, issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business.
Moreover, if material spill incidents were to occur in the future, the United States could elect to issue directives to temporarily cease drilling activities and, in any event, issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business.
Any of these industry operating risks could have a material adverse effect on our business, results of operations and financial condition. The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenues or curtailment of production from factors specifically affecting the Gulf of Mexico, including hurricanes.
Any of these industry operating risks could have a material adverse effect on our business, results of operations and financial condition. The geographic concentration of our properties in the Gulf of America subjects us to an increased risk of loss of revenues or curtailment of production from factors specifically affecting the Gulf of America, including hurricanes.
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 2023, 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 2024, any further decreases in commodity pricing could cause an impairment, which would result in a non-cash charge to earnings.
As a result, our need to replace proved reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their proved reserves over a similar time period, such as those producers who have a larger portion of their proved reserves in areas other than the Gulf of Mexico.
As a result, our need to replace proved reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their proved reserves over a similar time period, such as those producers who have a larger portion of their proved reserves in areas other than the Gulf of America.
We conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which presents unique operating risks. The deep shelf and the deepwater of the Gulf of Mexico are areas that have had less drilling activity due, in part, to their geological complexity, depth and higher cost to drill and ultimately develop.
We conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of America, which presents unique operating risks. The deep shelf and the deepwater of the Gulf of America are areas that have had less drilling activity due, in part, to their geological complexity, depth and higher cost to drill and ultimately develop.
Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or such requirements may be interpreted more restrictively, and asset removal technologies are constantly evolving, which may result in additional, increased or decreased costs.
Estimating future restoration and removal costs in the Gulf of America is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or such requirements may be interpreted more restrictively, and asset removal technologies are constantly evolving, which may result in additional, increased or decreased costs.
These requirements may limit the number of potential bidders for certain collateral in any foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral. We may not be able to repurchase the 11.75% Notes upon a change of control.
These requirements may limit the number of potential bidders for certain collateral in any foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral. We may not be able to repurchase the 10.75% Notes upon a change of control.
As a result, we may make significant increases or decreases to our estimated ARO in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions.
As a result, we may make significant increases or decreases to our estimated ARO in future periods. For example, because we operate in the Gulf of America, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions.
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, 2023.
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.
As a result, we can offer no assurance that we will find commercial quantities of oil and natural gas and, therefore, we can offer no assurance that we will achieve positive rates of return on our investments. We may not realize all of the anticipated benefits from our targeted acquisitions.
As a result, we can offer no assurance that we will find commercial quantities of oil and natural gas and, therefore, we can offer no assurance that we will achieve positive rates of return on our investments. We may not realize all of the anticipated benefits from our future acquisitions.
Depressed oil, NGL or natural gas prices adversely affect our business, financial condition, cash flow, liquidity or results of operations and could affect our ability to fund future capital expenditures needed to find and replace reserves, meet our financial commitments and to implement our business strategy.
Depressed oil, NGLs or natural gas prices adversely affect our business, financial condition, cash flow, liquidity or results of operations and could affect our ability to fund future capital expenditures needed to find and replace reserves, meet our financial commitments and to implement our business strategy.
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 11.75% 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 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.
Additional deepwater drilling laws, regulations and other restrictions, delays and other offshore-related developments in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.
Additional deepwater drilling laws, regulations and other restrictions, delays and other offshore-related developments in the Gulf of America may have a material adverse effect on our business, financial condition, or results of operations.
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.
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.
If we experience certain kinds of changes of control, we must give holders of the 11.75% Notes the opportunity to sell us their notes at 101% of their principal amount, plus accrued and unpaid interest.
If we experience certain kinds of changes of control, we must give holders of the 10.75% Notes the opportunity to sell us their notes at 101% of their principal amount, plus accrued and unpaid interest.
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 geological risk.
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.
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.
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.
For example, the government recently issued an order requiring the abandonment of certain facilities in the Gulf of Mexico, rendering the pipelines and other midstream assets that cross that facility incapable of operating.
For example, the government recently issued an order requiring the abandonment of certain facilities in the Gulf of America, rendering the pipelines and other midstream assets that cross that facility incapable of operating.
Our operations in the Gulf of Mexico require permits from federal and state governmental agencies in order to perform drilling and completion activities and conduct other regulated activities.
Our operations in the Gulf of America require permits from federal and state governmental agencies in order to perform drilling and completion activities and conduct other regulated activities.
Commodity derivative positions may limit our potential gains. In order to manage our exposure to price risk in the marketing of our oil and natural gas, we have entered, and may continue to enter, into oil and natural gas price commodity derivative positions with respect to a portion of our expected future production.
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.
At December 31, 2023, approximately 16% 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, 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.
The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital. 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. ​ 16 Table of Contents We are subject to drilling and other operational hazards.
Our ability to market our production depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities, which in some cases are owned and operated by third parties. 13 Table of Contents We depend upon third-party pipelines that provide delivery options from our facilities.
Our ability to market our production depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities, which in some cases are owned and operated by third parties. We also depend upon third-party pipelines that provide delivery options from our facilities.
The shut-in resulted in deferred production of approximately 774 MBoe based on production rates prior to the shut-in. 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 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.
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.
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.
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: ● 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; ● the actions of 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); ● 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+; ● 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.
If the proceeds of the sale of the collateral securing the 11.75% 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.
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.
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.
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.
Accordingly, our operations are subject to a series of climate-related transition risks, including regulatory, political and litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs. See Part I, Item 1 .
Nonetheless, our operations remain subject to a series of climate-related transition risks, including regulatory, political and litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs. See Part I, Item 1 .
While these commodity derivative positions are intended to reduce the effects of oil and natural gas price volatility, they may also limit future income if oil and natural gas prices were to rise substantially over the price established by such positions.
While these commodity derivative positions are intended to reduce the effects of price volatility, they may also limit future income if prices were to rise substantially over the price established by such positions.
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 indentures governing our outstanding notes 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.
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.
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, 2023, we have $18.0 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, 2024, we have $22.6 million of loss contingency recorded related to anticipated decommissioning obligations. See Part II, Item 8.
In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies.
From time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies.
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, 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.
We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. See Part I, Item 1.
We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.
Financial Statements and Supplementary Data — Note 19 — Contingencies for more information. 26 Table of Contents 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 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.
Certain provisions of our articles of incorporation and bylaws could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our stockholders.
Certain provisions of our articles of incorporation and bylaws, as well as the Texas Business Organizations Code, could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our stockholders.
Pursuant to the terms of our agreements with various sureties under our existing bonding arrangements, or under any future bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the surety’s sole discretion. Additional collateral would likely be in the form of cash or letters of credit.
Pursuant to the terms of our agreements with various sureties under our existing bonding arrangements, or under any future bonding arrangements we may enter into, we may be required to post collateral. Additional collateral would likely be in the form of cash or letters of credit.
The Biden administration has taken a number of actions that may result in stricter environmental, health and safety standards applicable to our operations and those of the oil and natural gas industry more generally.
The Biden administration took a number of actions that had potential to result in stricter environmental, health and safety standards applicable to our operations and those of the oil and natural gas industry more generally.
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 outstanding 11.75% Notes are secured by various liens on our oil and natural gas properties, excluding our Mobile Bay assets.
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.
Gulf Coast and adjacent waters on and beyond the OCS means that some or all of our properties could be affected by the same event should the Gulf of Mexico experience severe weather, including tropical storms and hurricanes; delays or decreases in production, the availability of equipment, facilities or services; changes in the status of pipelines that we depend on for transportation of our production to the marketplace; delays or decreases in the availability of capacity to transport, gather or process production; and changes in the regulatory environment. 17 Table of Contents For 2023, approximately 40% of our production and 19% of our total revenue was attributable to our Mobile Bay Properties.
Gulf Coast and adjacent waters on and beyond the OCS means that some or all of our properties could be affected by the same event should the Gulf of America experience severe weather, including tropical storms and hurricanes; delays or decreases in production, the availability of equipment, facilities or services; changes in the status of pipelines that we depend on for transportation of our production to the marketplace; delays or decreases in the availability of capacity to transport, gather or process production; and changes in the regulatory environment.
Our independent petroleum consultant estimates that 33.2% of our total proved reserves as of December 31, 2023 will be depleted within three years.
Our independent petroleum consultant estimates that 36.4% of our total proved reserves as of December 31, 2024 will be depleted within three years.
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, 2023, three fields, accounting for approximately 0.2 MMBoe (or 1.4%) of our 2023 production, 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, 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.
These covenants limit our ability and the ability of our restricted subsidiaries, among other things, to: ● make loans and investments; ● incur additional indebtedness or issue preferred stock; ● create certain liens; ● sell assets; ● enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; ● consolidate, merge or transfer all or substantially all of the assets of the Company; ● engage in transactions with our affiliates; ● pay dividends or make other distributions on capital stock or indebtedness; and ● create unrestricted subsidiaries.
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.
Proved reserves in the Gulf of Mexico generally have shorter reserve lives than proved reserves in many other producing regions of the United States, in part due to the difference in rules related to booking proved undeveloped reserves between conventional and unconventional basins.
All of our current production is from the Gulf of America. Proved reserves in the Gulf of America generally have shorter reserve lives than proved reserves in many other producing regions of the United States, in part due to the difference in rules related to booking PUDs between conventional and unconventional basins.
Regulatory agencies under the Biden administration may issue new or amended rulemakings regarding deepwater leasing, permitting or drilling that could result in more stringent or costly restrictions, delays or cancellations to our operations as well as those of similarly situated offshore energy companies on the OCS.
Issuance of new or amended rulemakings restricting deepwater leasing, permitting or drilling could result in more stringent or costly restrictions, delays or cancellations to our operations as well as those of similarly situated offshore energy companies on the OCS.
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. 28 Table of Contents 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, 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.
See Financial Statements and Supplementary Data– Note 4 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on our derivative contracts and transactions. We may enter into more derivative contracts in the future.
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.
The indenture governing our 11.75% Notes (the “Indenture”), our Credit Agreement and our Subsidiary Credit Agreement governing our indebtedness 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 New Credit Agreement contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt.
Similar events may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest.
In the past, tropical storms and hurricanes in the Gulf of America have caused catastrophic losses and property damage. Similar events may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest.
Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our assessments, we also perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems.
Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our assessments, we also perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. Additionally, such review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
Because a majority of our properties could experience the same conditions at the same time, these conditions could have a greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.
Because a majority of our properties could experience the same conditions at the same time, these conditions could have a greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area. A significant portion of our production, revenue and cash flow is concentrated in our Mobile Bay Properties.
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 2023, our Mobile Bay Properties were shut-in for 35 days for planned maintenance.
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.
If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt.
If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt. Even if new financing were then available, it may not be on terms that are acceptable to us.
These factors and the volatility of the energy markets, which we expect to continue, make it extremely difficult to predict future commodity prices with any certainty. ​ 12 Table of Contents If oil, NGL and natural gas prices decrease from their current levels, we may be required to further reduce the estimated volumes and future value associated with our total proved reserves or record impairments to the carrying values of our oil and natural gas properties.
If oil, NGL and natural gas prices decrease from their current levels, we may be required to further reduce the estimated volumes and future value associated with our total proved reserves or record impairments to the carrying values of our oil and natural gas properties.
Additionally, such review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. 19 Table of Contents There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations.
There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations.
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 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 changes the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements.
Finally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations. 23 Table of Contents We may be required to post cash collateral pursuant to our agreements with sureties under our existing or future bonding arrangements, which could have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our ARO plan and comply with our existing debt instruments.
We may be required to post cash collateral pursuant to our agreements with sureties under our existing or future bonding arrangements, which could have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our ARO plan and comply with our existing debt instruments.
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.
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.
In January 2024, the EPA proposed a rule implementing the IRA’s methane emissions charge. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA.
In January 2024, the EPA proposed a rule implementing the IRA’s methane emissions charge. Under this rule, finalized in November 2024, the methane emissions charge was established at $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 for 2026 and each year after.
Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow.
After utilizing our available sources of financing, we may be forced to raise additional debt or equity to fund such capital expenditures. Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow.
Such acquisitions could expose us to potentially significant liabilities, including plugging and abandonment and decommissioning liabilities . We expect to grow by expanding the exploitation and development of our existing assets, in addition to making targeted acquisitions in the Gulf of Mexico.
We expect to grow by expanding the exploitation and development of our existing assets, in addition to making targeted acquisitions in the Gulf of America.
Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations. 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 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.
In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control. 18 Table of Contents 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.
In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
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. ITEM 1B. UNRESOLVED STAFF COMMENTS None 31 Table of Contents
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.
We may be required to shut in wells because of a reduction in demand for our production or because of inadequacy or unavailability of pipelines, gathering system capacity or processing facilities. 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.
In addition, we may be required to shut in wells because of a reduction in demand for our production or because of inadequacy or unavailability of pipelines, gathering system capacity or processing facilities.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

7 edited+2 added−0 removed9 unchanged
Biggest changeEach of the members of the board of directors has also completed certificated training concerning IT security, IT fraud, and other common enterprise-level IT threats. 32 Table of Contents 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.
Biggest changeWe 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.
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).
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 ”) .
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 information technology (“IT”) and risk management systems and addresses both the corporate and the operational IT environment.
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.
Our Incident Response Plan applies to W&T personnel including contractors and partners that perform functions or services that require securing W&T information assets, and to all devices and networks that are owned by W&T. The Incident Response Plan details the coordinated, multi-functional approach for investigating, containing, and mitigating incidents.
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.
Additionally, all members of the board of directors attend quarterly training sessions through internal and external IT specialists, which include review of IT whitepapers, presentations, and other learning materials.
Additionally, all members of the board of directors attend quarterly training sessions through internal and external IT specialists, which include review of IT whitepapers, presentations, and other learning materials. Each of the members of the board of directors has also completed certificated training concerning IT security, IT fraud, and other common enterprise-level IT threats.
In the past three years, we have not experienced a material information security breach but may in the future. See Risk Factors in Part I, Item 1A in this Form 10-K for additional information.
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.
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. 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.
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
Our 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).
Added
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.

Item 2. Properties

Properties — owned and leased real estate

26 edited+19 added−21 removed9 unchanged
Biggest changeInvestors should not assume that PV-10, or PV-10 after ARO, of our proved oil and natural gas reserves shown above represent a current market value of our estimated oil and natural gas reserves. 35 Table of Contents The reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves is as follows (in millions): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2023 ​ 2022 ​ 2021 PV-10 ​ $ 1,080.9 ​ $ 3,128.6 ​ $ 1,621.9 ​ Future income taxes, discounted at 10% ​ (151.0) ​ (594.1) ​ (224.8) ​ PV-10 before ARO ​ 929.9 ​ 2,534.5 ​ 1,397.1 ​ Present value of estimated ARO, discounted at 10% ​ (246.7) ​ (271.5) ​ (241.1) ​ Standardized measure ​ $ 683.2 ​ $ 2,263.0 ​ $ 1,156.0 ​ ​ Changes in Proved Reserves The following table discloses our estimated changes in proved reserves during 2023: ​ ​ ​ ​ ​ MMBoe Proved reserves at December 31, 2022 ​ 165.3 Reserves additions (reductions): ​ ​ Revisions (1) (32.2) Purchases of minerals in place 2.6 Production (12.7) Net reserve additions (reductions) ​ (42.3) Total proved reserves at December 31, 2023 123.0 ​ (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, ​ ​ 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.
Management believes that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 and PV-10 after ARO are used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities.
Management believes that the non-GAAP financial measures of PV-10 and PV-10 before ARO are relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 and PV-10 before ARO are used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities.
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.
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.
In determining the estimated price for NGLs, a ratio was computed for each field of the NGL realized price compared to the oil realized price. This ratio was then applied to the oil price using SEC guidance. Such prices were held constant throughout the estimated lives of the reserves.
In determining the estimated price for NGLs, a ratio was computed for each field of the NGL realized price compared to the WTI oil spot price. This ratio was then applied to the oil price using SEC guidance. Such prices were held constant throughout the estimated lives of the reserves.
Management believes that the presentation of PV-10 and PV-10 after ARO provide useful information to investors because they are widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies.
Management believes that the presentation of PV-10 and PV-10 before ARO provide useful information to investors because they are widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies.
The NSAI report is based on its independent evaluation of engineering and geophysical data, product pricing, operating expenses, and the reasonableness of future capital requirements and development timing estimates provided by W&T. The scope and results of their procedures are summarized in a letter included as an exhibit to this Form 10-K.
The NSAI report is based on its independent evaluation of engineering and geophysical data, product pricing, operating expenses, and the reasonableness of future capital requirements and development timing estimates provided by us. The scope and results of their procedures are summarized in a letter included as an exhibit to this Form 10-K.
PV-10 and PV-10 after ARO are not measures of financial or operating performance under GAAP, nor are they intended to represent the current market value of our estimated oil and natural gas reserves.
PV-10 and PV-10 before ARO are not measures of financial or operating performance under GAAP, nor are they intended to represent the current market value of our estimated oil and natural gas reserves.
PV-10 and PV-10 after 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 cash flows as defined under GAAP.
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 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.
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.
(2) Includes 6 gross (5.1 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. ​ ​
(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. ​ ​
Three sidetrack PUD locations, one each at Matterhorn, Ship Shoal 349 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.
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.
Our Director of Reservoir Engineering has over 30 years of oil and gas industry experience and has managed the preparation of public company reserve estimates the last 18 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 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.
The primary technical person at NSAI responsible for overseeing the preparation of the reserves estimates presented herein has been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience.
The primary technical person at NSAI responsible for overseeing the preparation of the reserves estimates presented herein has been practicing consulting petroleum engineering at NSAI since 2015 and has over six years of prior industry experience.
See Proved Undeveloped Reserves below for a table reconciling the change in proved undeveloped reserves during 2023. See Financial Statements and Supplementary Data – Note 20 – 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 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.
The lone exceptions are at the Mississippi Canyon 243 field (“Matterhorn”), Ship Shoal 349 and 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 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 following table presents the timing of expiration of our undeveloped leasehold acreage: ​ ​ ​ ​ ​ ​ ​ Undeveloped Acreage ​ Net Percent of Total 2024 17,122 34% 2025 8,813 17% 2026 ​ — ​ 0% 2027 ​ 15,760 ​ 30% Thereafter ​ 10,000 ​ 19% Total 51,695 100% ​ ​ ​ ​ ​ In making decisions regarding drilling and operations activity for 2024 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.
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.
The following table presents changes in our PUDs (in MMBoe): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ 2023 2022 2021 PUDs, beginning of year 20.5 20.6 12.2 Revisions of previous estimates (1.3) (0.1) 8.4 Purchase of minerals in place 0.5 — — PUDs, end of year 19.7 20.5 20.6 ​ ​ ​ ​ ​ 36 Table of Contents The revisions of previous estimates during 2023 were due to changes in SEC pricing.
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 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 2024 1 14 % 2025 6 35 % 2026 ​ 4 ​ 48 % 2027 — — % 2028+ 1 3 % Total 12 100 % ​ As of December 31, 2023, we believe that we will be able to develop all but 3.1 MMBoe (approximately 16%) of the total 19.7 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 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.
Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process Our estimated proved reserve information as of December 31, 2023 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, 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.
He earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1989 and a master’s degree in Business Administration from the University of Houston in 1999. 37 Table of Contents Reserve Technologies Proved reserves are those quantities of oil 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, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X.
Reserve Technologies Proved reserves are those quantities of oil 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, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X.
We have the right to propose future exploration and development projects on the majority of our acreage.
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.
The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil Wells (1) ​ Gas Wells (2) ​ Total Wells ​ Gross Net Gross Net Gross Net Operated 110.0 ​ 101.3 ​ 86.0 ​ 76.8 196.0 178.1 Non-operated 33.0 ​ 5.8 ​ 12.0 ​ 5.4 45.0 11.2 Total 143.0 107.1 98.0 82.2 241.0 189.3 ​ ​ (1) Includes 10 gross (9.1 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, 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.
He has also served in various engineering and strategic planning roles with both Kerr-McGee and with Conoco, Inc.
He has also served in various engineering and strategic planning roles with both Kerr-McGee and with Conoco, Inc. He earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1989 and a master’s degree in Business Administration from the University of Houston in 1999.
Future production and development costs are based on year-end costs with no escalation. Reconciliation of Standardized Measure to PV-10 Neither PV-10 nor PV-10 after ARO are financial measures defined under 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.
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.
Drilling Activity The information presented below is based on the SEC’s criteria of completion or abandonment to determine wells drilled. Of the two gross (0.6 net) exploratory wells completed during 2022, one gross (0.3 net) well is currently producing.
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.
Developed and Undeveloped Acreage The following table summarizes our developed and undeveloped acreage at December 31, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed Acreage ​ Undeveloped Acreage ​ Total Acreage ​ Gross Net Gross Net Gross Net Shelf 386,916 ​ 326,652 ​ 48,698 ​ 45,935 435,614 372,587 Deepwater 141,929 ​ 56,540 ​ 11,520 ​ 5,760 153,449 62,300 Alabama State Waters ​ 8,038 ​ 5,144 ​ — ​ — ​ 8,038 ​ 5,144 Total 536,883 388,336 60,218 51,695 597,101 440,031 ​ ​ ​ Our net acreage decreased 15,026 net acres (3%) from December 31, 2022 due to lease expirations offset by leases acquired in the September 2023 acquisition. 38 Table of Contents Approximately 88.3% of our net acreage is held by production.
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.
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Oil and Natural Gas Producing Activities Our producing fields are located in federal and state waters in the Gulf of Mexico 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.
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Proved Reserves Our reserve information is derived from our reserve report prepared by Netherland, Sewell & Associates, Inc (“NSAI”), our independent reserve engineering firm.
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As of December 31, 2023, two of our fields located in the conventional shelf accounted for approximately 64.6% of our proved reserves on an energy equivalent basis.
Added
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.
Removed
The following table provides information for these fields: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Percent of ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ Company ​ Oil NGLs Natural Gas Equivalent Proved ​ ​ (MMBbls) ​ (MMBbls) ​ (Bcf) ​ (MMBoe) ​ Reserves Mobile Bay Properties ​ 0.2 ​ 10.1 ​ 320.4 ​ 63.7 ​ 51.8 % Ship Shoal 349 (Mahogany) ​ 11.7 ​ 1.0 ​ 18.7 ​ 15.8 ​ 12.8 % ​ The Mobile Bay Properties (as defined below) and Ship Shoal 349 field are two areas of operations of major significance, which we define as having year-end proved reserves of 10% or more of the Company’s total proved reserves on an energy equivalent basis.
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The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating of and Auditing of Oil & Gas Reserves information promulgated by the Society of Petroleum Engineers (SPE Standards).
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Each area of operation of major significance is described in detail below. Unless indicated otherwise, “drilling” or “drilled” in the descriptions below refers to when the drilling reached target depth, as this measurement usually has a higher correlation to changes in proved reserves compared to using the SEC’s definition for completion.
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NSAI used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy and reservoir modeling that are considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. The data in the table below represents estimates only.
Removed
The following are descriptions of these areas of operations: Mobile Bay Properties Our interests in certain oil and gas leasehold interests and associated wells and units located off the coast of Alabama, in state coastal and federal Gulf of Mexico waters approximately 70 miles south of Mobile, Alabama, are referred to as the “Mobile Bay Properties.” Cumulative field production for the Mobile Bay Properties through 2023 is approximately 896.6 MMBoe gross.
Added
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.
Removed
The Mobile Bay Properties produce from the Jurassic age Norphlet eolian sandstone at an average depth of 21,000 feet total vertical depth.
Added
Accordingly, reserve estimates may vary from the quantities of oil, NGLs and natural gas that are ultimately recovered.
Removed
As of December 31, 2023, 56 Norphlet wells have been drilled on the Mobile Bay Properties, 45 of which were successful and 27 of which are currently producing. 33 Table of Contents The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Mobile Bay Properties over the past three years: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2023 2022 2021 Net Sales: ​ ​ ​ Oil (MBbls) ​ 15 ​ 17 ​ 29 NGLs (MBbls) ​ 925 ​ 941 ​ 998 Natural gas (MMcf) ​ 24,826 ​ 30,052 ​ 32,940 Total oil equivalent (MBoe) ​ 5,078 ​ 5,967 ​ 6,516 Average realized sales prices: ​ ​ ​ ​ Oil ($/Bbl) ​ $ 41.12 ​ $ 51.60 ​ $ 27.49 NGLs ($/Bbl) ​ 22.53 ​ 35.45 ​ 30.84 Natural gas ($/Mcf) ​ 3.02 ​ 7.45 ​ 3.92 Oil equivalent ($/Boe) ​ 18.98 ​ 43.25 ​ 24.68 Average production costs: (1) ​ ​ ​ ​ Oil equivalent ($/Boe) ​ $ 17.39 ​ $ 11.81 ​ $ 7.34 ​ (1) Includes lease operating expenses, gathering and transportation costs and plugging and abandonment costs.
Added
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.
Removed
Ship Shoal 349 Field (Mahogany) Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, Louisiana. The field area covers Ship Shoal federal OCS blocks 349 and 359, with a single production platform on Ship Shoal block 349 in 375 feet of water (the “Ship Shoal 349”).
Added
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.
Removed
We own a 100% working interest in this field except for an interest in one well owned by Monza. Cumulative field production through 2023 is approximately 62.4 MMBoe gross. This field is a sub-salt development with nine productive horizons below salt at depths up to 18,000 feet.
Added
The standardized measure of discounted future net cash flows is the after-tax present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, without giving effect to non–property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.
Removed
As of December 31, 2023, 31 wells have been drilled and 26 were successful. Since acquiring an interest and subsequently taking over as operator, we have directly participated in drilling 17 wells with a 100% success rate. There has been no drilling activity since 2019 at Ship Shoal 349.
Added
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.
Removed
The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Ship Shoal 349 field over the past three years: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2023 2022 2021 Net Sales: ​ ​ ​ Oil (MBbls) ​ 1,269 ​ 1,313 ​ 1,667 NGLs (MBbls) ​ 68 ​ 104 ​ 88 Natural gas (MMcf) ​ 1,709 ​ 1,827 ​ 2,565 Total oil equivalent (MBoe) ​ 1,622 ​ 1,722 ​ 2,182 Average realized sales prices: ​ ​ ​ ​ Oil ($/Bbl) ​ $ 70.86 ​ $ 88.36 ​ $ 65.27 NGLs ($/Bbl) ​ 28.17 ​ 40.50 ​ 36.85 Natural gas ($/Mcf) ​ 3.41 ​ 7.15 ​ 4.00 Oil equivalent ($/Boe) ​ 60.22 ​ 71.03 ​ 56.05 Average production costs: (1) ​ ​ ​ ​ Oil equivalent ($/Boe) ​ $ 7.61 ​ $ 7.63 ​ $ 6.60 ​ (1) Includes lease operating expenses, gathering and transportation costs and plugging and abandonment costs. 34 Table of Contents Proved Reserves Our proved reserves were estimated by Netherland, Sewell & Associates, Inc (“NSAI”), our independent petroleum consultant, and amounts provided in this Form 10-K are consistent with filings we make with other federal agencies.
Added
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.
Removed
Our proved reserves as of December 31, 2023, 2022 and 2021 are summarized below: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ NGLs ​ Natural ​ ​ ​ PV-10 ​ ​ (MMBbls) ​ (MMBbls) ​ Gas (Bcf) ​ MMBoe ​ (in millions) December 31, 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved developed producing 22.2 ​ 10.0 ​ 299.4 ​ 82.1 $ 750.1 Proved developed non-producing 5.2 ​ 2.7 ​ 80.0 ​ 21.2 204.1 Total proved developed 27.4 12.7 379.4 103.3 954.2 Proved undeveloped 9.6 ​ 1.0 ​ 54.6 ​ 19.7 126.7 Total proved 37.0 13.7 434.0 123.0 $ 1,080.9 December 31, 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved developed producing 23.7 16.1 499.2 123.0 $ 2,280.8 Proved developed non-producing 7.4 1.5 76.8 21.8 457.6 Total proved developed 31.1 17.6 576.0 144.8 2,738.4 Proved undeveloped 9.5 1.3 58.6 20.5 390.2 Total proved 40.6 18.9 634.6 165.3 $ 3,128.6 December 31, 2021 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved developed producing 20.8 16.4 507.9 121.9 $ 1,185.3 Proved developed non-producing 6.8 1.4 41.3 15.1 222.9 Total proved developed 27.6 17.8 549.2 137.0 1,408.2 Proved undeveloped 9.6 1.3 58.4 20.6 213.7 Total proved 37.2 19.1 607.6 157.6 $ 1,621.9 In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2023 were determined to be economically producible under existing economic conditions, which requires the use of SEC pricing.
Added
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.
Removed
Applying this methodology, the WTI oil average spot price of $78.21 per barrel and the Henry Hub natural gas average spot price of $2.64 per MMBtu were utilized as the referenced price and, after adjusting for quality, transportation, fees, energy content and regional price differences, the adjusted average product prices were $74.79 per barrel for oil, $24.08 per barrel for NGLs and $2.74 per Mcf for natural gas.
Added
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.
Removed
Our estimates of proved reserves, PV-10 and the standardized measure as December 31, 2023 are calculated based upon SEC mandated 2023 unweighted average first-day-of-the-month oil and natural gas benchmark prices, and adjusting for quality, transportation fees, energy content and regional price differentials, which may or may not represent current prices.
Added
Proved Undeveloped Reserves PUDs are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. All proved undeveloped locations conform to the SEC rules defining proved undeveloped locations.
Removed
If prices fall below the 2023 levels, absent significant proved reserve additions, this may reduce future estimated proved reserve volumes due to lower economic limits and economic return thresholds for undeveloped reserves, as well as impact our results of operations, cash flows, quarterly full cost impairment ceiling tests and volume-dependent depletion cost calculations.
Added
We do not have any reserves that would be classified as synthetic oil or synthetic natural gas.
Removed
See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 in this Form 10-K for additional information. Proved Undeveloped Reserves Our PUDs were estimated by NSAI, our independent petroleum consultant. Future development costs associated with our PUDs at December 31, 2023 were estimated at $437.9 million.
Added
We annually review all PUDs to ensure an appropriate plan for development exists.
Removed
The revisions in 2022 and 2021 were primarily due to technical revisions and revisions due to changes in SEC pricing at certain of our Ship Shoal fields.
Added
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.
Removed
Based on the latest reserve report, these PUD locations are expected to be developed in 2025 and 2035.
Added
Future development costs associated with our PUDs at December 31, 2024 were estimated at $659.8 million.
Removed
The following table sets forth our drilling activity for completed wells on a gross basis: ​ ​ ​ ​ ​ ​ ​ ​ ​ Completed ​ 2023 2022 2021 Conventional shelf — 1 — Deepwater — 1 — Wells operated by W&T — 1 — ​ The following table summarizes our development and exploration offshore wells completed over the past three years: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2023 2022 2021 Development wells completed: ​ ​ ​ ​ ​ ​ Gross wells — — — Net wells — — — Exploration wells completed: Gross wells — 2 — Net wells — 0.6 — ​ During 2022, we completed one well and abandoned one well in which we had a 25% working interest.
Added
Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process Our policies and procedures regarding internal controls over the recording of our reserves is structured to objectively and accurately estimate our reserves quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s regulations.
Removed
During 2021, we participated in the drilling of an exploration well which was non-commercial. Our success rate related to our development and exploration wells was 50% in 2022.
Removed
Capital Expenditures See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Expenditures under Part II, Item 7 in this Form 10-K for capital expenditure information. 39 Table of Contents Productive Wells Productive wells consist of producing wells and wells capable of production.

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 19 – 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. ​ 40 Table of Contents PART II
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

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeStock Performance Graph The graph below shows the cumulative total shareholder return assuming the investment of $100 in our common stock and the reinvestment of all dividends thereafter. 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.
Biggest changeThe 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.
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, 2024, there were 134 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 March 1, 2025, there were 127 registered holders of our common stock.
Issuer Purchases of Equity Securities None. Unregistered Sales of Equity Securities None. 41 Table of Contents ITEM 6. [RESERVED]
Issuer Purchases of Equity Securities None. Unregistered Sales of Equity Securities None. ITEM 6. [RESERVED]
Other than this dividend, we did not declare or pay any cash dividends on our common stock during 2023 and 2022. The decision to pay additional dividends on our common stock is at the discretion of our board of directors and is subject to periodic review of our performance, which includes the current economic environment and applicable debt agreement restrictions.
The decision to pay additional dividends on our common stock is at the discretion of our board of directors and is subject to periodic review of our performance, which includes the current economic environment and applicable debt agreement restrictions.
Dividends On November 8, 2023, we announced that our board of directors approved the implementation of a quarterly cash dividend payable to holders of our common stock. The initial cash dividend of $0.01 per share of common stock, or $1.5 million, was paid on December 22, 2023, to shareholders of record at the close of business on November 28, 2023.
Dividends 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.
Added
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.
Added
The results are based on an investment of $100 in our common stock, the S&P Oil and Gas Exploration and the S&P 500. The graph assumes reinvestment of dividends.

Item 7. Management's Discussion & Analysis

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

65 edited+85 added−110 removed11 unchanged
Biggest changeThe following table presents our sources of revenue as a percentage of total revenue: ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2023 2022 Oil 71.6 % ​ 56.9 % NGLs 6.1 % ​ 6.2 % Natural gas 20.7 % ​ 35.2 % Other 1.6 % ​ 1.7 % ​ ​ 46 Table of Contents The information below provides a discussion of, and an analysis of significant variance in, our oil, NGL and natural gas revenues, production volumes and average sales prices for 2023 and 2022 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ 2023 2022 ​ ​ Change Revenues: ​ ​ ​ ​ ​ ​ ​ ​ Oil $ 381,389 ​ $ 524,274 ​ $ (142,885) NGLs 32,446 ​ 56,964 ​ (24,518) Natural gas 110,158 ​ 323,831 ​ (213,673) Other 8,663 ​ 15,928 ​ (7,265) Total revenues $ 532,656 ​ $ 920,997 ​ $ (388,341) ​ ​ ​ ​ ​ ​ ​ ​ ​ Production Volumes: ​ ​ Oil (MBbls) 5,050 ​ 5,602 ​ (552) NGLs (MBbls) 1,415 ​ 1,554 ​ (139) Natural gas (MMcf) 37,591 ​ 44,808 ​ (7,217) Total oil equivalent (MBoe) 12,730 ​ 14,624 ​ (1,894) ​ ​ ​ ​ ​ ​ ​ ​ ​ Average daily equivalent sales (Boe/day) ​ 34,877 ​ 40,067 ​ ​ (5,190) ​ ​ ​ ​ ​ ​ ​ ​ ​ Average realized sales prices: ​ ​ ​ ​ Oil ($/Bbl) $ 75.52 ​ $ 93.59 ​ $ (18.07) NGLs ($/Bbl) 22.93 ​ 36.66 ​ (13.73) Natural gas ($/Mcf) 2.93 ​ 7.23 ​ (4.30) Oil equivalent ($/Boe) 41.16 ​ 61.89 ​ ​ (20.73) Oil equivalent ($/Boe), including realized commodity derivatives ​ 40.84 ​ ​ 59.15 ​ (18.31) ​ Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between 2023 and 2022 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Price Volume ​ Total Oil $ (91,250) ​ $ (51,635) ​ $ (142,885) NGLs (19,398) ​ ​ (5,120) ​ (24,518) Natural gas (161,513) ​ ​ (52,160) ​ (213,673) ​ $ (272,161) ​ $ (108,915) ​ $ (381,076) ​ Realized Prices on the Sale of Oil, NGLs and Natural Gas – Our average realized sales price for oil differs from the WTI average spot price primarily due to premiums or discounts, quality adjustments, location adjustments and volume weighting (collectively referred to as differentials).
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 .
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with Part I, Item 1. Business , Item 2. Properties , Item 1A. Risk Factors and Item 7A.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with Part I, Item 1. Business , Item 1A. Risk Factors , Item 2. Properties and Item 7A.
Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our growth to take advantage of the current commodity environment and will allow us to meet our cash requirements for at least the next 12 months.
Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our growth to take advantage of the current commodity environment and will allow us to meet our cash requirements for at least the next 12 months and beyond.
Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month.
Derivative gain, net Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month.
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 2023 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 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.
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 2023 and 2022 items and comparisons between 2023 and 2022.
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.
A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by our wholly-owned subsidiaries and through our proportionately consolidated interest in Monza.
A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by our wholly-owned subsidiaries and through our proportionately consolidated interest in Monza Energy LLC.
Discussions of 2021 items and comparisons between 2022 and 2021 that are not included in the 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, 2022.
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.
Production taxes consist of severance taxes levied by the Alabama Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state, respectively.
Production taxes consist of severance taxes levied by the Alabama Department of Revenue , the Louisiana Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state.
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.
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.
General and administrative expenses (“G&A”) – G&A expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, share-based compensation costs, audit and other fees for professional services and legal compliance.
General and administrative expenses General and administrative (“G&A”) expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, share-based compensation costs, audit and other fees for professional services and legal compliance.
In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate.
In estimating the liability associated with our AROs, we utilize several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate.
We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments. 51 Table of Contents Acquisitions We have grown by making strategic acquisitions of producing properties in the Gulf of Mexico. We seek opportunities where we can exploit additional drilling projects and reduce costs.
We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments. Acquisitions We have grown by making strategic acquisitions of producing properties in the Gulf of America. We seek opportunities where we can exploit additional drilling projects and reduce costs.
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 2023 was 3.4%.
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.
Such uncertainties may include: ● ceiling test write-downs of the carrying value of our oil and gas properties; ● reductions in our proved reserves and the estimated value thereof; ● additional supplemental bonding and potential collateral requirements; ● reductions in our borrowing base under the Credit Agreement; and ● our ability to fund capital expenditures needed to replace produced reserves, which must be replaced on a long-term basis to provide cash to fund liquidity needs described above.
Such uncertainties may include: ● ceiling test write-downs of the carrying value of our oil and natural gas properties; ● reductions in our proved reserves and the estimated value thereof; ● additional supplemental bonding and potential collateral requirements; and ● our ability to fund capital expenditures needed to replace produced reserves, which must be replaced on a long-term basis to provide cash to fund liquidity needs.
Our preliminary capital expenditure budget for 2024 has been established in the range of $35.0 million to $45.0 million, which excludes acquisitions. In our view of the outlook for 2024, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2024 and beyond while providing liquidity to make strategic acquisitions.
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.
On a per Boe basis, lease operating expenses increased to $20.24 per Boe during 2023 compared to $15.35 per Boe during 2022. On a component basis, base lease operating expenses increased $15.2 million, workover expenses increased $9.7 million and facility maintenance expenses increased $8.7 million. These increases were partially offset by a decrease of $0.3 million in hurricane repairs.
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.
As of December 31, 2023, we had $173.3 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, 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.
We have obligations to plug and abandon all wells, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations.
Asset Retirement Obligations We have significant obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug and abandon all wells, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations.
The DD&A rate increased to $9.01 per Boe in 2023 from $7.33 per Boe in 2022. The DD&A rate per Boe increased primarily as a result of a higher depreciable base due to increases in capital expenditures, future development costs and capitalized ARO and lower proved reserves.
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.
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 Mexico. As of December 31, 2023, we held working interests in 53 offshore producing fields in federal and state waters (which include 44 fields in federal waters and nine 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, 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).
Although the Federal Reserve has stated that they will begin reducing the benchmark rate in 2024, if inflation were to continue to rise, it is possible the Federal Reserve would continue to take action they deem necessary to bring inflation down and to ensure price stability, including further 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.
However, if inflation were to continue to rise again, it is possible the Federal Reserve would continue to take action they deem necessary to bring inflation down and to ensure price stability, including targeted 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.
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. These joint interest obligations for future commitments cannot be determined due to the variability of factors involved.
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.
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 $33.3 million to $257.7 million in 2023 compared to $224.4 million in 2022.
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 realized sales prices received for our oil, NGLs and natural gas production are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and international geopolitical and economic events.
Prices of oil, NGLs and natural gas have historically been volatile and can fluctuate significantly over short periods of time for many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and international geopolitical and economic events.
We currently have under lease approximately 597,100 gross acres (440,000 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama state waters, 435,600 gross acres on the conventional shelf and approximately 153,500 gross acres in the deepwater.
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.
Deferred Production – Our oil, NGLs and natural gas production is 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, the transportation, gathering or processing of production and weather events. For 2023, we estimate deferred production was approximately 2,541 MBoe.
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.
Estimating the future restoration and removal cost requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal.
Estimating the future restoration and removal cost requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
As a result of the derivative contracts we have on our anticipated natural gas production volumes through April 2028, we expect these activities to continue to impact net income based on fluctuations in market prices for natural gas. As of December 31, 2023, we do not have any open oil contracts.
As a result of the derivative contracts we have on our anticipated natural gas production volumes through April 2028, we expect these activities to continue to impact net income based on fluctuations in market prices for natural gas. Other expense, net During 2024, other expense, net, was $18.1 million, compared to $5.6 million for 2023.
Additionally, other liabilities and commitments include estimates of minimum quantities obligations for certain pipeline contracts which were assumed in conjunction with the purchase of an interest in the Heidelberg field. These amounts exclude our 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 $0.6 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.
As of December 31, 2023, we had approximately $454.2 million of bonds outstanding, with the majority related to plugging and abandonment obligations. The amounts are based on current market rates and conditions for these types of bonds and are subject to change. Excluded are potential increases in surety bond requirements which cannot be determined.
The amounts are based on current market rates and conditions for these types of bonds and are subject to change. Excluded are potential increases in surety bond requirements which cannot be determined.
Contractual Obligations and Commitments Our material cash commitments from known contractual and other obligations consist primarily of obligations for long-term debt and related interest, operating leases, ARO and other obligations as part of normal operations.
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.
Investing activities – Net cash used in investing activities for 2023 decreased $13.5 million compared to 2022. This was primarily due to decreases of $24.1 million in acquisition of property interests and $1.7 million in investment in oil and natural gas properties, partially offset by the purchase of the corporate aircraft and furniture, fixtures and other.
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.
Risk Factors and Financial Statements and Supplementary Data – Note 8 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.
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.
Cash Flow Information The following table summarizes cash flows provided by (used in) by type of activity for the following periods (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ ​ 2023 ​ 2022 ​ ​ Change Operating activities ​ $ 115,326 ​ $ 339,530 ​ $ (224,204) Investing activities ​ (81,608) ​ (95,080) ​ 13,472 Financing activities ​ (321,737) ​ (28,892) ​ (292,845) ​ ​ ​ ​ ​ ​ 50 Table of Contents Operating activities – Net cash provided by operating activities for 2023 was $115.3 million, decreasing $224.2 million from 2022.
Cash Flow Information The following table summarizes cash flows provided by (used in) by type of activity for the following periods (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ ​ 2024 ​ 2023 ​ ​ Change Operating activities ​ $ 59,539 ​ $ 115,326 ​ $ (55,787) Investing activities ​ (118,177) ​ (81,608) ​ (36,569) Financing activities ​ (8,562) ​ (321,737) ​ 313,175 ​ Operating activities – Net cash provided by operating activities for 2024 was $59.5 million, decreasing $55.8 million from 2023.
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, ​ ​ ​ ​ 2023 2022 ​ Change Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating expenses ​ $ 257,676 ​ $ 224,414 ​ $ 33,262 Gathering, transportation and production taxes ​ ​ 26,250 ​ ​ 35,128 ​ ​ (8,878) Depreciation, depletion and amortization ​ 114,677 ​ ​ 107,122 ​ 7,555 Asset retirement obligations accretion expense ​ 29,018 ​ ​ 26,508 ​ 2,510 General and administrative expenses ​ ​ 75,541 ​ ​ 73,747 ​ ​ 1,794 Total operating expenses ​ $ 503,162 ​ $ 466,919 ​ $ 36,243 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average per Boe ($/Boe): ​ ​ ​ Lease operating expenses ​ $ 20.24 ​ $ 15.35 ​ $ 4.89 Gathering, transportation and production taxes ​ 2.06 ​ 2.40 ​ (0.34) Depreciation, depletion and amortization ​ 9.01 ​ 7.33 ​ 1.68 Asset retirement obligations accretion expense ​ ​ 2.28 ​ ​ 1.81 ​ ​ 0.47 General and administrative expenses ​ 5.93 ​ 5.04 ​ 0.89 Total operating expenses ​ $ 39.52 ​ $ 31.93 ​ $ 7.59 ​ Lease operating expenses – Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of Mexico.
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, ​ ​ ​ ​ 2024 2023 ​ Change Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating expenses ​ $ 281,488 ​ $ 257,676 ​ $ 23,812 Gathering, transportation and production taxes ​ ​ 28,177 ​ ​ 26,250 ​ ​ 1,927 Depreciation, depletion and amortization ​ 143,025 ​ ​ 114,677 ​ 28,348 Asset retirement obligations accretion expense ​ 32,374 ​ ​ 29,018 ​ 3,356 General and administrative expenses ​ ​ 82,391 ​ ​ 75,541 ​ ​ 6,850 Total operating expenses ​ $ 567,455 ​ $ 503,162 ​ $ 64,293 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average per Boe ($/Boe): ​ ​ ​ Lease operating expenses ​ $ 23.10 ​ $ 20.24 ​ $ 2.86 Gathering, transportation and production taxes ​ 2.31 ​ 2.06 ​ 0.25 Depreciation, depletion and amortization ​ 11.74 ​ 9.01 ​ 2.73 Asset retirement obligations accretion expense ​ ​ 2.66 ​ ​ 2.28 ​ ​ 0.38 General and administrative expenses ​ 6.76 ​ 5.93 ​ 0.83 Total operating expenses ​ $ 46.57 ​ $ 39.52 ​ $ 7.05 ​ 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.
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. 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.
We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire the associated assets.
We accrue a liability with respect to these obligations based on our estimates of the timing and the fair value of an obligation to replace, remove or retire the associated assets. After initial recording, the liability is accreted to its future estimated value using an assumed cost of funds.
For more information on the BOEM and financial assurance obligations to that agency, see Business – Environmental, Health and Safety Matters and Government Regulations – Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 of this Form 10-K. 45 Table of Contents Surety Bond Collateral – In prior years, some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us and may request additional collateral from us in the future, which could be significant and could impact our liquidity.
For more information on the BOEM and financial assurance obligations to that agency, see Business – Environmental, Health and Safety Matters and Government Regulations – Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 of this Form 10-K.
On December 13, 2023, we entered into a purchase and sale agreement to acquire rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of Mexico, among other assets, for a gross purchase price of $72.0 million, subject to customary purchase price adjustments.
In January 2024, we closed on the 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, subject to customary purchase price adjustments. The transaction was funded with cash on hand.
During 2022, the $85.5 million derivative loss recorded for oil and natural gas derivative contracts consisted of $125.1 million of premium payments and realized losses on settled contracts and $39.6 million of unrealized gain, net from the increase in fair value of open contracts.
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.
Our significant accounting policies are detailed in Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K.
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.
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.
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.
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.
This was primarily due to the redemption of the $552.5 million principal amount outstanding of the 9.75% Notes in February 2023 partially offset by the net cash proceeds of $275.0 million received from the issuance of the 11.75% Notes in January 2023. ​ 50 Table of Contents 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.
BOEM Matters – The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS. As of December 31, 2023, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to financial assurance obligations.
For 2024, we estimate deferred production was approximately 2.6 MMBoe, excluding the deferred production from the hurricanes. BOEM Matters The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS.
In 2023, the rate differed from the federal statutory rate of 21% primarily due to adjustments in the valuation allowance, compensation adjustments and the impact of state income taxes. In 2022, the rate differed from the federal statutory rate primarily due to adjustments in the valuation allowance and the impact of state income taxes.
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.
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, ​ 2023 2022 Exploration (1) ​ $ 4,659 ​ $ 13,339 Development (1) ​ 35,356 ​ 20,390 Acquisitions of interests ​ 27,384 ​ 51,474 Seismic and other ​ 1,263 ​ 7,903 Investments in oil and gas property/equipment – accrual basis ​ $ 68,662 ​ $ 93,106 ​ ​ ​ ​ ​ ​ (1) Reported geographically in the subsequent table.
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.
As these estimates are for work to be performed in the future, and in many cases, several years in the future, actual expenditures could be substantially different than our estimates.
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.
These decreases in operating cash flow were partially offset by the changes in operating assets and liabilities which increased operating cash flows by $25.1 million primarily related to (i) lower accounts receivable balance due to decreased realized prices , (ii) and lower accounts payable and accrued liabilities balances in the current period and (iii) a $42.3 million decrease in ARO settlements.
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.
In September 2023, we acquired working interests in certain oil and natural gas producing assets in the central and eastern shelf region of the Gulf of Mexico for $27.4 million. This transaction is described in more detail under Financial Statements and Supplementary Data – Note 7 – Acquisitions , under Part II, Item 8 of this Annual Report.
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.
Spot prices for Henry Hub natural gas averaged $2.53 per MMBtu in 2023, and the EIA is forecasting that Henry Hub prices will average $2.65 in 2024.
The EIA expects the spot prices for Henry Hub natural gas to average $3.14 per MMBtu in 2025 and $3.97 per MMBtu in 2026, up from a historically low average of $2.19 per MMBtu in 2024.
Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. During 2023, we incurred $12.0 million in workover expenses primarily at our Mobile Bay Properties due to numerous workover projects including well cleanout, recovering of fishing tools and stimulating to return the wells back to production.
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.
During both 2023 and 2022, other expense primarily consisted of additional expenses for net abandonment obligations pertaining to a number of legacy Gulf of Mexico properties . Income tax expense – Our effective tax rates for 2023 and 2022 were 54.0% and 18.8%, respectively.
During 2024 and 2023, other expense primarily consisted of $20.9 million and $6.2 million, respectively, of additional expenses for net abandonment obligations pertaining to a number of legacy Gulf of America properties, partially offset by fees paid by producers to tie into our subsea equipment at one of our wells .
We were in compliance with all applicable covenants of the Term Loan, Credit Agreement and the 11.75% Notes indenture as of and for the period ended December 31, 2023. Dividend s On November 8, 2023, we announced that our board of directors approved the implementation of a quarterly cash dividend payable to holders of common stock.
For additional information about our long-term debt, see Part II, Item 8. Financial Statements and Supplementary Data – Note 5 – Debt and Note 19 – Subsequent Events of this Annual Report. Dividend s In November 2023, we announced that our board of directors approved the implementation of a quarterly cash dividend payable to holders of common stock.
In addition, expenses related to our insurance coverage also increased due to higher premiums on our policies that were renewed in June 2023. Workover and facility maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production.
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.
The contract is to begin in February 2025 and terminate in October 2025. (4) Other liabilities and commitments primarily consist of estimated fees for surety bonds related to obligations under certain purchase and sale agreements and for supplemental bonding for plugging and abandonment.
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.
A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. We apply significant judgment in evaluating tax positions and estimating our provision for income taxes.
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.
Continued inflationary pressures and increased commodity prices may also result in increases in the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. The United States has experienced a rise in inflation since October 2021.
In addition to the impact of volatile commodity prices on our operations, continuing inflation could also impact our sales margins and profitability. The United States has experienced a rise in inflation since October 2021.
We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.
Significant judgments and estimates are required in determining consolidated income tax expense. Deferred income taxes arise from temporary differences between the book carrying amounts and the tax basis of assets and liabilities, which will result in taxable or deductible amounts in the future.
Recent Developments On December 13, 2023, we entered into a purchase and sale agreement to acquire rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of Mexico, among other assets, for a gross purchase price of $72.0 million, subject to customary purchase price adjustments.
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.
We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management. Full Cost Accounting 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. Accounting for Oil and Natural Gas Properties We account for our oil and natural gas operations using the full cost method of accounting.
RESULTS OF OPERATIONS Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 Revenues Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs.
For more information on risks associated with our bonding, please see Risk Factors under Part I, Item 1A of this Form 10-K. RESULTS OF OPERATIONS Revenues Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs.
Accretion expense increased to $29.0 million in 2023 compared to $26.5 million in 2022 primarily due to the increase in our ARO liability (see Part II, Item 8. Financial Statements and Supplementary Data — Note 8 — Asset Retirement Obligations ).
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.
Gathering, transportation and production taxes decreased to $26.3 million in 2023 compared to $35.1 million in 2022, primarily due to lower production volumes and realized prices partially offset by the transportation contract related to the properties acquired in 2022. 48 Table of Contents Depreciation, depletion and amortization – Depreciation, depletion and amortization expense (“DD&A”) is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves.
Depreciation, depletion and amortization Depreciation, depletion and amortization expense (“DD&A”) is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities.
We used the net proceeds from the issuance of the 11.75% Notes and $296.1 million of cash on hand to fund the redemption. See Financial Statements and Supplementary Data –Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.
We also terminated the Credit Agreement and used the net proceeds from the issuance of the 10.75% Notes and cash on hand to repay in full all outstanding amounts owed under the Term Loan and the 11.75% Notes outstanding.
Removed
Business Outlook Our cash flows are materially impacted by the prices of commodities we produce (oil, NGLs and natural gas). During 2023, commodity prices experienced significant declines from those experienced during 2022.
Added
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.
Removed
The average WTI oil price for 2023 was approximately 18% lower than the average for 2022 and the average Henry Hub natural gas price for 2023 was approximately 61% lower than the average for 2022.
Added
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.
Removed
While the current outlook for commodity prices is favorable, other global factors could adversely impact our operations, and commodity prices could significantly decline from current levels. In addition, the prices of goods and services used in our business can vary and impact our cash flows and margins.
Added
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.
Removed
Our margins in 2023 decreased from 2022 primarily due to lower average realized commodity prices, coupled with higher operating expenses.
Added
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.
Removed
We measure margins using an Adjusted EBITDA margin which we define as net income (loss) before income tax expense, net interest expense, depreciation, depletion, amortization and accretion, unrealized commodity derivative gain or loss and the effects of derivative premium payments, allowance for credit losses, non-cash incentive compensation, non-recurring costs related to IT services transition, non-ARO P&A costs, and other miscellaneous costs as a percent of revenue, which is not a financial measurement under GAAP.
Added
(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.
Removed
Although we have historically increased our reserves and production through acquisitions, our drilling program, and other projects that optimize production on existing wells, our production decreased 13% in 2023 from the prior year.
Added
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.
Removed
Our proved reserves also decreased by 42.3 MMBoe in 2023, primarily due to the significant decrease in commodity prices in 2023 as compared to 2022. 42 Table of Contents We continually monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2024 plans.
Added
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.
Removed
See Liquidity and Capital Resources under this Item 7 in this Form 10-K for additional information.

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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, ​ ​ 2023 ​ 2022 Oil ($/Bbl): ​ ​ ​ Average realized sales price, before the effects of derivative settlements ​ $ 75.52 ​ $ 93.59 Effects of realized commodity derivatives ​ — ​ (12.35) Average realized sales price, including realized commodity derivatives ​ $ 75.52 ​ $ 81.24 ​ ​ ​ ​ ​ ​ ​ Natural Gas ($/Mcf) ​ ​ Average realized sales price, before the effects of derivative settlements ​ $ 2.93 ​ $ 7.23 Effects of realized commodity derivatives ​ (0.11) ​ 0.65 Average realized sales price, including realized commodity derivatives ​ $ 2.82 ​ $ 7.88 ​ During 2023, our average realized natural gas price after the effect of derivatives decreased 64.2% during 2023 to $2.82 per Mcf from $7.88 per Mcf during 2022.
Biggest changeThe following table summarizes the historical results of our hedging activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2024 ​ 2023 Natural Gas ($/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.
Our derivatives will not mitigate all of the commodity price risks of our forecasted sales of natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.
Our derivatives will not mitigate all the commodity price risks of our forecasted sales of natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.
We do not designate our derivative contracts as hedges for accounting purposes. Accordingly, the changes in the fair value of these derivative contracts are recognized currently in earnings. Commodity Price Risk Our major market risk exposure is the fluctuation of prices for oil, NGL and natural gas. These fluctuations have a direct impact on our revenues, earnings and cash flow.
We do not designate our derivative contracts as hedges for accounting purposes. Accordingly, the changes in the fair value of these derivative contracts are recognized currently in earnings. Commodity Price Risk Our major market risk exposure is the fluctuation of prices for oil, NGLs and natural gas. These fluctuations have a direct impact on our revenues, earnings and cash flow.
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, costless collars, purchased calls, and purchased puts.
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.
For example, assuming a 10% decline in our average realized oil, NGL and natural gas sales prices in 2023 and assuming no other items had changed, our revenue would have decreased by approximately $52.4 million in 2023. 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 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.
We do not have any derivative contracts related to interest rates as of December 31, 2023. 59 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, 2024. ​ 56 Table of Contents
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 which is primarily impacted by the rates for the Secured Overnight Financing Rate, and the current margin is 6.0% per annum.
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.
Removed
Interest Rate Risk As of December 31, 2023, our interest rate risk exposure is mitigated as of result of fixed interest rates on all our long-term debt outstanding.

Other WTI 10-K year-over-year comparisons