FLME Flame Acquisition Corp. - 10-K

Item 1A.     Risk Factors

You should carefully consider the following risks as well as the other information included in this annual report, including the section titled “ Management’s Discussion and Analysis of Financial Condition and Results of Operations ” and our financial statements and related notes thereto. Any of the following risks could materially and adversely affect our business, financial condition or results of operations. However, the selected risks described below are not the only risks facing us. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially and adversely affect our business, financial condition or results of operations.

Risk Factors Summary

The following is a summary of the principal risks and uncertainties described in more detail in this annual report:

• The requirements to resume petroleum transportation through Pipeline Segments 324 and 325 include those set forth in a Consent Decree with federal and state agencies. While the operator of the Pipeline Segments believes it has satisfied all of the conditions to resuming petroleum transportation included under the Consent Decree, there is no assurance that we will be successful in resuming petroleum transportation through Pipeline Segments 324 and 325 and recommence oil sales in a timely manner.

• In order to commence operations pursuant to the OS&T Strategy, we will require clearances and permitting, including from BOEM.

• The timing of returning wells to production is subject to risks that may cause delays and initial production rates are expected to decline.

• Our assumptions and estimates regarding the total costs associated with recommencing oil sales may be inaccurate.

• There is no guarantee that we will have sufficient cash to recommence oil sales.

• Oil, natural gas and natural gas liquids, or “NGL(s)”, prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition.

• If commodity prices decline and remain depressed for a prolonged period, our business may become uneconomical and result in additional write downs of the value of our properties, which may adversely affect our financial condition and our ability to fund operations.

• An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we expect to receive for our future oil sales could significantly reduce our cash flow and adversely affect our financial condition.

• The estimated quantities of petroleum contained in the SYU Assets are classified as “contingent resources” rather than “reserves” because they are subject to numerous contingencies. There is no assurance that any of the petroleum contained in the SYU Assets will ever be recovered or reclassified as “reserves.”

• Developing and producing oil, natural gas and NGLs are costly and high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash flows. Many of these risks are heightened for us due to the fact that some of our equipment has not been used for petroleum production or transportation for more than ten years.

• The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

• Development and production of oil, natural gas and NGLs in offshore waters have inherent and historically higher risk than similar activities onshore.

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• Oil and natural gas producers’ operations are substantially dependent on the availability of water and the disposal of waste, including produced water and drilling fluids. Restrictions on the ability to obtain water or dispose of waste may impact our operations.

• The unavailability or high cost of rigs, equipment, supplies and crews could delay our operations, increase our costs and delay forecasted revenue.

• The third parties on whom we rely for transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

• Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil, natural gas and NGL production.

• We may incur losses as a result of title defects or deficiencies in our properties.

• We do not own all of the land on which our assets are located or all of the land that we must traverse in order to conduct our operations. There are disputes with respect to certain of the rights-of-way or other interests and any unfavorable outcomes of such disputes could require us to incur additional costs.

• Under the terms of the Senior Secured Term Loan, the loans thereunder will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons, and the terms on which we will be able to refinance the Senior Secured Term Loan will depend on then-prevalent market conditions.

• Restrictive covenants in the Senior Secured Term Loan or any future agreements governing our indebtedness could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

• Our business plans require a significant amount of capital. In addition, our future capital needs may require us to issue additional equity or debt securities that may dilute our stockholders or introduce covenants that may restrict our operations or ability to pay dividends.

• We are subject to complex federal, state, local and other laws, regulations and permits that could adversely affect the cost, manner, ability or feasibility of conducting our operations.

• Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs, could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we expect to produce.

• Attempts by the California state government to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels in California.

• Our assets are located exclusively onshore and offshore in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.

• All of our operations are conducted in areas that may be at risk of damage from fire, mudslides, earthquakes or other natural disasters.

• We may be required to post cash collateral pursuant to our agreements with sureties, letter of credit providers or regulators under our existing or future bonding or other arrangements, which may have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan and our asset retirement obligation plan and comply with the agreements governing our existing or future indebtedness.

• Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.

• The market prices of our securities could be highly volatile or may decline regardless of our operating performance. You may lose some or all of your investment.

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Risks Related to Recommencing Oil Sales

The requirements to resume petroleum transportation through Pipeline Segments 324 and 325 include those set forth in a Consent Decree with federal and state agencies. While the operator of the Pipeline Segments believes it has satisfied all of the conditions to resuming petroleum transportation included under the Consent Decree, there is no assurance that we will be successful in resuming petroleum transportation through Pipeline Segments 324 and 325 and recommence oil sales in a timely manner.

Production from the SYU Assets was suspended as a result of the Line 901 incident and consequent suspension of service. In May 2025 we restarted production from the SYU Assets and resumed petroleum transportation through the Santa Ynez Pipeline System. However, absent OS&T offtake, our business depends on resuming petroleum transportation through Pipeline Segments 324 and 325. We are required to satisfy certain requirements related to Pipeline Segments 324 and 325 before we can recommence oil sales. Such requirements include conditions set forth in a U.S. federal district court Consent Decree executed by Plains and relevant U.S. and State of California government agencies. Sable believes all such requirements have been satisfied. However, there is no guarantee that the State of California government agencies will agree that such requirements have been met, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to repay or refinance the Senior Secured Term Loan. On January 14, 2026, both Plains and the Company submitted letters to the United States Department of Justice Environment and Natural Resources Division and the California Office of the Attorney General Natural Resources Law Section regarding the termination of the Consent Decree because the prerequisites for termination have been satisfied, however, there is no guarantee these parties will agree the prerequisites have been satisfied and terminate the Consent Decree. See “ Risk Factors—Under the terms of the Senior Secured Term Loan, the loans thereunder will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons, and the terms on which we will be able to refinance the Senior Secured Term Loan will depend on then-prevalent market conditions.”

In order to commence operations pursuant to the OS&T Strategy, we will require clearances and permitting, including from BOEM.

We may experience delays in obtaining or be unable to obtain required permits, including authorizations necessary to recommence oil sales pursuant to the OS&T Strategy, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to repay or refinance the Senior Secured Term Loan. In particular, prior to implementation of the OS&T Strategy, regulatory authorizations are required, including clearance from BOEM. If we do not receive regulatory clearances in connection with the OS&T Strategy in a timely manner, we may not be able to reach commercial sales on our estimated timeline of the fourth quarter of 2026.

While the previous operator of the SYU was able to utilize the OS&T Strategy to process SYU production in federal waters from 1981 to 1994 under previously issued permits, there is no assurance that we will be able to successfully obtain the agency clearance or permits required to recommence oil sales pursuant to the OS&T Strategy or that no additional state or federal clearances or permits will be required in the future.

The timing of returning wells to production is subject to risks that may cause delays and initial production rates are expected to decline.

We returned a number of wells to production on Platform Harmony beginning in May 2025, and we expect to return a number of additional wells to production on Platforms Harmony, Heritage and Hondo. Operations on offshore platforms are subject to numerous risks and potential delays.

In addition, oil and natural gas wells typically exhibit a decline in production over time. Accordingly, initial production rates as our wells are brought back into production are expected to be higher than the rate of sustained production at such wells. There is substantial uncertainty regarding the amount and timing of production decline from recently reopened wells.

Our assumptions and estimates regarding the total costs associated with recommencing oil sales may be inaccurate.

We currently estimate no remaining start-up expenses to recommence oil sales via the Santa Ynez Pipeline System, other than applicable legal expenses. If we instead pursue the OS&T Strategy, we currently estimate remaining start-up expenses of approximately $475.0 million to recommence offshore oil sales, excluding corporate working capital. The expenditures will primarily be directed towards preparing for the implementation of the OS&T Strategy, including the procurement of a suitable vessel and necessary upgrade and installation costs with respect to such vessel and our platforms, obtaining necessary regulatory approvals and recommencing oil sales in the fourth quarter of 2026. This estimate of costs to recommence oil sales considers currently available facts and presently enacted laws and regulations, but it is subject to uncertainties associated with the assumptions that we have made. For example, because the markets for OS&T vessels and

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vessel refurbishment and upgrading are competitive, and our estimates for the cost of procurement and planned upgrades are based on our understanding of the relevant markets and current supply of suitable vessels and contracts, the actual cost of such a vessel and the related upgrades may exceed our expectations. In addition, the costs of equipment, repairs and maintenance, the costs of operating personnel, the costs to obtain governmental approvals, and legal, consulting and other professional expenses could turn out to be higher than we have estimated. In addition, commencement of sales pursuant to the OS&T Strategy may be delayed if additional financing is not procured in a timely fashion and therefore our capital expenditure plan is delayed. We may experience increases in costs and delays.

We are currently evaluating and pursuing the OS&T Strategy and have curtailed certain capital expenditures relating to the Santa Ynez Pipeline System. If in the future we are permitted to conduct commercial sales using such assets, we intend to do so and would incur such curtailed Santa Ynez Pipeline System costs, in addition to the costs related to the pursuit of the OS&T Strategy. Accordingly, our assumptions and estimates may change in future periods based on future events and total costs may materially increase. Therefore, we can provide no assurance that we will not have to incur additional costs in future periods that are significantly higher than our estimated costs to recommence oil sales.

There is no guarantee that we will have sufficient cash to recommence oil sales.

Until we recommence oil sales, either via the Santa Ynez Pipeline System or the OS&T Strategy, we will not generate any revenue or cash flows from operations and will rely on cash on hand to fund the operations necessary to recommence oil sales. If we do not have sufficient cash on hand to recommence oil sales, we may need to raise additional capital to continue our operations, and this capital may not be available on acceptable terms or at all. If we do not have sufficient cash on hand or are unable to obtain additional funding on a timely basis, we may be unable to recommence oil sale, which could materially affect our business, financial condition and results of operations.

Risks Related to the Business of the Company

Oil, natural gas and natural gas liquids, or “NGL(s)”, prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition.

Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:

• the regional, domestic and foreign supply of oil, natural gas and NGLs;

• the level of commodity prices and expectations about future commodity prices;

• the level of global oil and natural gas exploration and production;

• localized supply and demand fundamentals, including the proximity and capacity of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;

• the cost of exploring for, developing, producing and transporting oil, natural gas and NGLs;

• the price and quantity of foreign imports;

• political and economic conditions in oil producing countries, including conflicts in or among the Middle East, Africa, South America and Russia;

• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• speculative trading in crude oil and natural gas derivative contracts;

• the level of consumer product demand;

• weather conditions and other natural disasters;

• risks associated with operating drilling rigs;

• technological advances affecting exploration and production operations and overall energy consumption;

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• domestic and foreign governmental regulations and taxes;

• the impact of energy conservation efforts;

• the continued threat of terrorism and the impact of military and other action, including the Russia-Ukraine war and its destabilizing effect on the European continent and the global oil and natural gas markets;

• the price and availability of competitors’ supplies of oil and natural gas and alternative fuels; and

• overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2025, the NYMEX-Brent oil futures price ranged from a high of $127.98 per Bbl on March 8, 2022 to a low of $51.09 per Bbl January 4, 2021, while the NYMEX-Henry Hub natural gas futures price ranged from a high of $9.68 per MMBtu on August 22, 2022 to a low of $1.58 per MMBtu on March 26, 2024. For the year ended December 31, 2025, the NYMEX-Brent oil futures price ranged from a high of $82.03 per Bbl on January 15, 2025 to a low of $58.92 per Bbl on December 16, 2025 and the NYMEX-Henry Hub natural gas futures price ranged from a high of $5.29 per MMBtu on December 5, 2025 to a low of $2.70 per MMBtu on August 25, 2025. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and different pricing characteristics, have sustained depressed realized prices during this period and are generally correlated with the price of oil. While recent events have led to elevated oil, natural gas and NGL prices, an extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition.

If commodity prices decline and remain depressed for a prolonged period, our business may become uneconomical and result in additional write downs of the value of our properties, which may adversely affect our financial condition and our ability to fund operations.

Oil, natural gas and NGL prices have experienced significant volatility over the past few years. An extended decline in commodity prices could render our business uneconomical and result in a downward adjustment of our assets, which would reduce our ability to fund our operations. An extended decline, or sustained marked uncertainty, in commodity prices may cause us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may in the future incur impairment charges that could have a material adverse effect on our results of operations in the period taken. Sustained declines or uncertainty in commodities prices may adversely affect our financial condition, results of operations, ability to reduce debt, ability to pay dividends and the timing of our capital projects.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we expect to receive for our future oil sales could significantly reduce our cash flow and adversely affect our financial condition.

The prices that we expect to receive for our future sales will often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX or ICE, that are used for calculating hedge positions. The prices we expect to receive for our future sales are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, California oil typically has a lower gravity, and a portion typically has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil will likely require more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. These discounts, if significant, could reduce our cash flows and adversely affect our results of operations and financial condition.

The estimated quantities of petroleum contained in the SYU Assets are classified as “contingent resources” rather than “reserves” because they are subject to numerous contingencies. There is no assurance that any of the petroleum contained in the SYU Assets will ever be recovered or reclassified as “reserves.”

The resources are contingent upon (1) approval and/or inspection from federal, state and local regulators to recommence oil sales, (2) reestablishment of oil transportation systems to deliver production to market and (3) commitment to restart the wells and facilities. Some or all of the contingent resources may be reclassified as “reserves” if all of the contingencies are successfully resolved but there is no assurance that the contingencies will be resolved or resolved in a timely manner or that any of the petroleum in the SYU Assets will be recovered.

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Our hedging strategy in the future may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.

We expect that we will develop and maintain a portfolio of commodity derivative contracts covering a specified percentage or range of our estimated production from proved developed producing reserves over a one-to-three-year period at any given point in time. These commodity derivative contracts may include natural gas, oil and NGL financial swaps. The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices and price expectations at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil, natural gas and NGL prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

Developing and producing oil, natural gas and NGLs are costly and high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash flows. Many of these risks are heightened for us due to the fact that some of our equipment has not been used for petroleum production or transportation for more than ten years.

Our development and production operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of many factors, including:

• high costs, shortages or delivery delays of rigs, equipment, labor, electrical power or other services;

• unusual or unexpected geological formations;

• composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;

• unexpected operational events and conditions;

• failure of down hole equipment and tubulars;

• loss of wellbore mechanical integrity;

• failure, unavailability or shortage of capacity of gathering and transportation pipelines, or other transportation facilities;

• human errors, facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour natural gas;

• excessive wall loss or other loss of pipeline integrity;

• title problems;

• litigation, including landowner lawsuits;

• loss of drilling fluid circulation;

• hydrocarbon or oilfield chemical spills;

• fires, blowouts, surface craterings and explosions;

• surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids;

• delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements;

• delays due to operations in environmentally sensitive areas; and

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• adverse weather conditions and natural disasters.

Many of these risks are heightened for us due to the fact that some of our equipment has not been used for petroleum production or transportation for more than ten years. Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations are delayed or canceled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition and results of operations may be adversely affected. If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our business, financial condition, results of operations and cash flows.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“ Dodd-Frank Act ”), enacted in 2010, establishes federal oversight and regulation of, among other things, the over-the-counter derivatives market and certain participants in that market, including us. Rules and regulations applicable to over-the-counter derivatives transactions may affect both the size of positions that we may hold and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain. See “ Business—Other Regulation of the Oil and Natural Gas Industry-Derivatives Regulation ” for additional information.

Development and production of oil, natural gas and NGLs in offshore waters have inherent and historically higher risk than similar activities onshore.

Our offshore operations are subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than onshore oil and natural gas activities. We are vulnerable to the risks associated with operating offshore California, including risks relating to:

• impacts of climate change and natural disasters such as earthquakes, tidal waves, mudslides, fires and floods;

• oil field service costs and availability;

• compliance with environmental and other laws and regulations;

• third-party marine vessels;

• response capabilities for personnel, equipment and environmental incidents;

• remediation and other costs resulting from oil spills, releases of hazardous materials and other environmental and natural resource damages; and

• failure of equipment or facilities.

In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because significant portions of our offshore operations are conducted in environmentally sensitive areas, including areas with significant residential populations and public and commercial infrastructure. An accidental oil spill or release on or related to offshore properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of remediating a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be subject to regulatory scrutiny and liable for costs and damages, which costs and damages could be material to our business, financial condition or results of operations and could subject us to criminal and civil penalties. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.

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Oil and natural gas producers’ operations are substantially dependent on the availability of water and the disposal of waste, including produced water and drilling fluids. Restrictions on the ability to obtain water or dispose of waste may impact our operations.

Water is an essential component of oil and natural gas production during the drilling and production process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our development and production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. The Clean Water Act imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into “waters of the United States.” Permits must be obtained to discharge pollutants to such waters and to conduct construction activities in such waters, which include certain wetlands. The Clean Water Act and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for the disposal and recycling of produced water, drilling fluids and other wastes may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. In addition, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes. In some jurisdictions, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity or resulted in stricter regulatory requirements relating to the location and operation of underground injection wells. Any orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect our operations. See “ Business—Environmental, Occupational Safety and Health Matters and Regulations-Water Discharges ” for an additional description of the laws and regulations relating to the discharge of water and other wastes that affect us.

The unavailability or high cost of rigs, equipment, supplies and crews could delay our operations, increase our costs and delay forecasted revenue.

Our industry is cyclical, and historically there have been periodic shortages of rigs, equipment, supplies and crew. Sustained declines in oil and natural gas prices may reduce the number of service providers for such rigs, equipment, supplies and crews, contributing to or resulting in shortages. Alternatively, during periods of higher oil and natural gas prices, the demand for rigs, equipment, supplies and crews is increased and can lead to shortages of, and increasing costs for, development equipment, supplies, services and personnel. While we have mitigated some of these issues with our dedicated rig, shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned relating to the fields where our properties are located. In addition, some of our operations require supply materials for production, such as CO2, which could become subject to shortages and increased costs. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and impact our development plan, which would thus affect our financial conduction, results of operations and our cash flows.

The third parties on whom we rely for transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.

The operations of the third parties on whom we rely for transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely for transportation services could impact the availability of those services. Any potential impact to the availability of transportation services could impact our ability to market and sell our production, which could have a material adverse effect on our business, financial condition and results of operations. See “ Business—Environmental, Occupational Safety and Health Matters and Regulations ” and “ Business-Other Regulation of the Oil and Natural Gas Industry ” for a description of the laws and regulations that affect the third parties on whom we rely for transportation services.

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Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil, natural gas and NGL production.

The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by us or third parties. The amount of oil, natural gas and NGLs that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. For example, our ability to produce and sell oil from SYU will depend on the continued availability of the pipeline infrastructure between platforms, for delivery of that oil to shore, and for further delivery to market, and any unavailability of that pipeline infrastructure could cause us to shut in all or a portion of the production from the SYU Assets for the length of such unavailability. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months or more. In many cases, we are provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business, financial condition, results of operations and cash flows. Additionally, recent petroleum refinery conversions and announcements of potential refinery closures in California could further impact our ability to market and transport our products efficiently.

Loss of our key executive officers or other key personnel, or an inability to attract and retain such officers and personnel, could negatively affect our business and, in one instance, could cause a default under the primary agreement governing our existing indebtedness.

Our future success depends on the skills, experience and efforts of our executive officers. The sudden loss of any of these executives’ services or our failure to appropriately plan for any expected executive succession could materially and adversely affect our business and prospects, as we may not be able to find suitable individuals to replace them on a timely basis, if at all. Additionally, we also depend on our ability to attract and retain qualified personnel to operate and expand our business. If we fail to attract or retain talented new employees, our business and results of operations could be negatively affected. Workers may choose to pursue employment with our competitors or in other fields. Additionally, the Senior Secured Term Loan requires that James C. Flores, our Chairman and Chief Executive Officer, remains directly and actively involved in the day-to-day management of our business, subject to the right of the holder of such indebtedness to approve his replacement, such approval not to be unreasonably withheld.

We may incur losses as a result of title defects or deficiencies in our properties.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we have done extensive title diligence in advance of the Business Combination and typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title or other defects or deficiencies may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

We do not own all of the land on which our assets are located or all of the land that we must traverse in order to conduct our operations. There are disputes with respect to certain of the rights-of-way or other interests and any unfavorable outcomes of such disputes could require us to incur additional costs.

We do not own in fee all of the land on which our assets are located or all of the land that we must traverse in order to conduct our operations. Rather, many of the properties or rights are derived from leases, surface use agreements, rights-of-way or other easement rights and, therefore, we will be subject to the possibility of more onerous terms or increased costs to retain necessary land access if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. Some of the rights to land owned by third parties and governmental agencies are obtained for a specific period of time and under certain conditions. We believe that we will have obtained sufficient right-of-way grants from public authorities (subject to receipt of certain governmental permits and consents) and private parties for us to operate our business, and obtained court approval of a settlement expressly confirming those rights with the overwhelming majority of the private landowners in September 2024 (see Grey Fox Settlement, infra). However, at least one private landowner along sectors of Pipeline Segment 324 has continued to make claims that the easement agreements with it is no longer effective. Further, on May 8, 2025, State Parks issued a Right of Entry (“ROE”) Permit that allowed the Company to perform certain specified repair and maintenance activities on portions of Segment 325 located within Gaviota State Park. On July 27, 2025, State Parks issued an annual ROE Permit relating to Pipeline Segment 325 within Gaviota State Park. Sable is also working with State Parks on the terms of a long-term easement agreement Our loss of any of these surface use agreements, rights-of-way or other

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easement rights through lapse or failure to satisfy or maintain certain conditions could require us to cease operations on the affected land or find alternative locations for our operations at increased costs, any of which could have a material adverse effect on our business, financial condition and results of operations.

Under the terms of the Senior Secured Term Loan, the loans thereunder will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons, and the terms on which we will be able to refinance the Senior Secured Term Loan will depend on then-prevalent market conditions.

The Senior Secured Term Loan will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan). Our ability to obtain any refinancing of the Senior Secured Term Loan, and the terms of any such refinancing, will depend on market conditions at the time of any such refinancing. There can be no assurance that we will be able to obtain such refinancing on terms commercially acceptable to us, or at all.

Restrictive covenants in the Senior Secured Term Loan or any future agreements governing our indebtedness could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Restrictive covenants in the Senior Secured Term Loan impose significant operating and financial restrictions on us and our subsidiaries and we may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the Senior Secured Term Loan unless we gain EM’s consent. These restrictions limit our ability to, among other things:

• engage in mergers, consolidations, liquidations, or dissolutions;

• create or incur debt or liens;

• make certain debt prepayments;

• pay dividends, distributions, management fees or certain other restricted payments;

• make investments, acquisitions, loans, or purchase oil and gas properties;

• sell, assign, farm-out or dispose of any property;

• enter into transactions with affiliates;

• enter into, subject to certain exceptions, any agreement that prohibits or restricts liens securing the Senior Secured Term Loan, payments of dividends to us, or payment of debt owed to us and our subsidiaries; and

• change the nature of our business.

The Senior Secured Term Loan also contains representations and warranties, affirmative covenants, additional negative covenants and events of default (including a change of control), including a financial liquidity covenant that requires us to have not less than $25 million in unrestricted cash, measured at the end of each month. In addition, during the pendency of the Senior Secured Term Loan and in case of an event of default thereunder, EM may exercise all remedies at law or equity, and may foreclose upon substantially all of our assets and the assets of our subsidiaries, including, in the event of a deficiency, cash and any other assets not acquired from EM in the Business Combination to the extent constituting collateral under the applicable financing documents.

We may in the future refinance our existing indebtedness or incur new indebtedness at variable rates and without the option to pay interest in-kind, which would subject us to interest rate risk and could cause our debt service obligations to increase significantly.

The outstanding principal amount under our Senior Secured Term Loan bears interest at a fixed rate and we have the option of capitalizing the interest onto the principal rather than paying cash interest, but we may in the future refinance our existing indebtedness or incur new indebtedness with variable rates and mandatory cash interest payments, which would expose us to interest rate risk and additional liquidity burdens. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the principal amount remained the same, and our net income and cash available for servicing our indebtedness would decrease.

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Our business plans require a significant amount of capital. In addition, our future capital needs may require us to issue additional equity or debt securities that may dilute our stockholders or introduce covenants that may restrict our operations or ability to pay dividends.

Our business and operations may consume resources faster than we anticipate. In the future, we may need to raise additional funds through the issuance of new equity or debt securities, or a combination thereof. Additional financing may not be available on favorable terms or at all. If adequate funds are not available on acceptable terms, we may be unable to fund our capital requirements. If we issue new debt, the debt holders would have rights senior to holders of our Common Stock to make claims on our assets and the terms of any debt could restrict our operations, including our ability to pay dividends on our Common Stock. If we issue additional equity securities or securities convertible into equity securities, existing stockholders will experience dilution and the new equity securities could have rights senior to those of our Common Stock. Because our decision to issue securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings and their impact on the market price of our Common Stock.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors and other counterparties. Some of our vendors and other counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors and other counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’ and other counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors or other counterparties could adversely affect our business, financial condition, results of operations and cash flows.

We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks. Expenses not covered by our insurance could have a material adverse effect on our financial position and results of operations.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, all of which could cause substantial financial losses. The location of any properties and other assets near environmentally sensitive areas or near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of potential damages resulting from these risks. Other catastrophic events such as earthquakes, floods, mudslides, fires, droughts, contagious diseases, terrorist attacks and other events that cause operations to cease or be curtailed may adversely affect our business and the communities in which we operate. For example, utilities have begun to suspend electric services to avoid wildfires during windy periods in California, a business disruption risk that is not insured. We may be unable to obtain, or may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of any of these or other similar events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, suspension or disruption of operations, substantial revenue losses and repairs to resume operations.

We maintain insurance coverage against potential losses that we believe is customary in the industry. However, insurance against all operational risk is not available to us. These insurance policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. A liability, claim or other loss not fully covered by insurance could have a material adverse effect on our business, financial position, results of operations and cash flows.

We may be unable to compete effectively with larger companies.

The oil and natural gas industry is intensely competitive with respect to marketing oil and natural gas and securing equipment and trained personnel. Many of our larger competitors not only drill for and produce oil and natural gas but also

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carry on refining operations and market petroleum and other products on a regional, national or worldwide basis, which offers them greater access and economies of scale. In addition, there is substantial competition for investment capital in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition, results of operations and cash flows.

We are subject to complex federal, state, local and other laws, regulations and permits that could adversely affect the cost, manner, ability or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations administered by governmental authorities vested with broad authority relating to the exploration for and the development, production and transportation of oil, natural gas, and NGLs. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. In order to recommence oil sales via the Santa Ynez Pipeline System, we must comply with a number of requirements related to Pipeline Segments 324 and 325, including conditions set forth in a U.S. federal district court Consent Decree executed by Plains and relevant U.S. and State of California government agencies. In order to commence operations pursuant to the OS&T Strategy, we will require regulatory authorizations, including clearance from BOEM. We may incur substantial costs in order to maintain compliance with these existing laws and regulations, and we may experience delays in procuring required approvals, which may increase our costs or delay our ability to produce revenue. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our oil, natural gas, and NGLs development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the release or discharge of materials into or through the environment, worker health and safety aspects of our operations, or otherwise relating to property rights, environmental protection, resource protection, and damage to natural resources. These laws and regulations may impose numerous obligations applicable to our operations, including regulated drilling activities; operation of the Santa Ynez Pipeline System; installation and use of an OS&T; the restriction of types, quantities and concentrations of materials that can be released or discharged into or through the environment; required authorizations for, or the limitation or prohibition of, drilling, production and transportation activities on certain lands lying within wilderness, wetlands, seismically active, park and recreation areas and other protected or preserved areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution and natural resources damages potentially resulting from our operations. The EPA, BOEM, BSEE, PHMSA, OSFM, CalGEM, Coastal Commission, CDFW, Regional Board, the SLC, State Parks and numerous other governmental authorities have the authority to enforce compliance with these laws and regulations and the permits or other authorizations issued by them, often requiring difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, injunctive and mitigation relief, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. We may also experience delays in obtaining or be unable to obtain required permits, including authorizations necessary to recommence oil sales, which may delay or interrupt our operations and limit our growth and revenue, or may impact our ability to repay or refinance the Senior Secured Term Loan, which will mature on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan).

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate or conduct other response actions at or in relation to contaminated properties currently owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from the consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. New laws and regulations continue to be enacted, particularly at the state level, and environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Additionally, any changes in environmental regulations related to biodiversity protection could impose further operational constraints and costs. To the extent laws are

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enacted, or other governmental action is taken that restricts drilling, production and transportation activities, or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

See “ Business—Environmental, Occupational Safety and Health Matters and Regulations ” and “ Business-Other Regulation of the Oil and Natural Gas Industry ” for a description of the more significant laws and regulations that affect us.

Changes in tax law may materially adversely affect our financial condition, results of operations and cash flows.

New income, sales, use or other tax laws, statutes, rules, regulations or ordinances are continuously being enacted, proposed, interpreted, changed, or modified, any of which could adversely affect our business operations and financial performance. For example, on July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”), was signed into law in the United States, which includes revisions to key business tax provisions such as the reinstatement of bonus depreciation deductions for qualified property, the restoration of an EBITDA-based business interest expense limitation, the revision and expansion of certain renewable energy tax credits that were previously available under the IRA and the implementation of changes relating to the computation of certain taxes in respect of non-US activities. Since future changes to tax legislation and regulations are unknown, we cannot predict the ultimate impact such changes may have on our business. To the extent that these or other changes have a negative impact on us or our consumers, including as a result of related uncertainty, these changes may materially and adversely impact us, our business, financial condition, results of operations and cash flow.

The listing of a species as either “threatened” or “endangered” under the U.S. Endangered Species Act and/or the California Endangered Species Act could result in increased costs, new operating restrictions, or delays in our operations, which could adversely affect our results of operations and financial condition.

The U.S. Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our activities in those areas or during certain seasons, such as breeding and nesting seasons. The listing of species in areas where we operate or, alternatively, entry into certain range-wide conservation planning agreements could result in increased costs to us from species protection measures, time delays or limitations on our activities, which costs, delays or limitations may be significant and could adversely affect our results of operations and financial position.

Conservation measures, technological advances and increasing public attention and activism with respect to climate change and environmental matters could reduce demand for oil, natural gas and NGLs and have an adverse effect on our business, financial condition and reputation.

Fuel conservation measures, alternative fuel requirements, incentives to conserve energy or use alternative energy sources, increasing consumer demand for alternatives to oil, natural gas and NGLs, and technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGLs. Such initiatives or related activism aimed at limiting climate change and reducing air pollution, as well as negative investor sentiment toward our industry and the impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, cash flows, and ability to access capital. Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change, may also lead to increased litigation risk, and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business. In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance or have caused other redressable injuries under federal and/or state common law. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations. Moreover, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gas activities.

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Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs, could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we expect to produce.

In December 2009, the EPA published its findings that emissions of GHGs present a danger to public health and the environment because emissions of such gases are contributing to the warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act. In addition, the EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. The adoption or revision and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil, natural gas and NGLs we produce. Such climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

On August 16, 2022, President Biden signed into law the IRA, which targets methane from oil and gas sources by imposing an applicable “waste emissions charge” on petroleum and natural gas production facilities that exceed a specified waste emissions threshold and requiring the reporting of emissions that exceed 25,000 metric tons of carbon dioxide equivalent per year. On November 18, 2024, the EPA published a final rule to implement this waste emissions charge as required by the IRA. However, on March 14, 2025, Congress a joint resolution under the Congressional Review Act disapproved EPA’s final rule, and EPA removed the implementing regulations in May 2025. Subsequently, Congress amended the Clean Air Act in July 2025 to delay the start of this methane emissions charge until emissions reported for calendar year 2034 and to constrain EPA’s implementation authority and funding for that program.

In addition to the IRA, almost one-half of the states have taken legal measures to reduce emissions of GHGs, including through the planned development of GHG emission inventories and/or regional GHGs cap and trade programs. On an international level, the United States was one of nearly 200 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emissions reduction goals beginning in 2020. However, the United States formally announced its intent to withdraw from the Paris Agreement in November 2019, which became effective in November 2020. On January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. On January 20, 2025, President Trump signed an executive order initiating the re-withdraw of the United States from the agreement, and the United States’ exit became effective in January 2026. In addition, various states and local governments have vowed to continue to enact regulations to achieve the goals of the Paris Agreement.

On February 12, 2026, EPA rescinded its 2009 “Endangerment Finding” under Clean Air Act Section 202(a). In the rescission rule, EPA determined that Clean Air Act Section 202(a)(1) does not authorize EPA to prescribe emission standards in response to global climate change for multiple reasons, and accordingly EPA rescinded GHG emission standards and related regulatory provisions for new vehicles and engines. It is expected that this rescission rule will be challenged in federal court.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require additional reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil, natural gas and NGL that we produce. Finally, it should be noted that numerous scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur in sufficient proximity to our facilities, they could have an adverse effect on our financial condition and results of operations. For example, such effects could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, increases in our costs of operation or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. See “ Business—Environmental, Occupational Safety and Health Matters and Regulations-Regulation of ‘Greenhouse Gas’ Emissions ” for a description of the climate change laws and regulations that affect us. Also see “ Risk Factors—Risks Related to the Business of the Company-Attempts by the California state government to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels in California .”

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Attempts by the California state government to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels in California.

California, where portions of the Santa Ynez Pipeline System are located, is heavily regulated with respect to oil and gas operations. Federal, state and local laws and regulations govern most aspects of exploration, production, processing and transportation of hydrocarbons in California. The regulatory burden on the industry increases our costs and consequently may have an adverse effect upon capital expenditures, earnings or competitive position. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil, or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects.

Additionally, the California state government recently has taken several actions that could adversely impact future oil and gas production and other activities in the state. For example:

• In September 2020, the California Governor issued an executive order that seeks to reduce both the supply of and demand for fossil fuels in the state. The executive order established several goals and directed several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: (1) phasing out the sale of emissions-producing vehicles; (2) developing strategies for the closure and repurposing of oil and gas facilities in California; and (3) calling on the California State Legislature to enact new laws prohibiting hydraulic fracturing in the state by 2024. The executive order also directed CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly strengthened regulations.

• In October 2020, the California Governor issued an executive order that established a state goal to conserve at least 30% of California’s land and coastal waters by 2030 and directed state agencies to implement other measures to mitigate climate change and strengthen biodiversity.

• On July 1, 2025, amendments to the Low Carbon Fuel Standard (“LCFS”) Regulation took effect. The LCFS Program is a market-based compliance measure that is designed to create economic value from low-carbon and renewable fuel technologies, with a stated goal of reducing greenhouse gas emissions in California. The recent amendments increase both the pre- and post-2030 stringency of carbon intensity benchmarks. Specifically, they increase the carbon intensity reduction targets from 20% to 30% by 2030, and aim for a 90% reduction by 2045, based on a 2010 baseline.

• On September 19, 2025, California Governor Gavin Newsom signed Assembly Bill 1207 and Senate Bill 840 into law. Together, the new laws re-authorize and extend California’s cap-and-trade program – now renamed the “cap-and-invest” program – through December 31, 2045. This program sets a price on greenhouse emissions that over time may reduce demand for oil and gas. On January 20, 2026, CARB commenced a rulemaking to amend the cap-and-invest regulations, which CARB anticipates to approve at its May 28, 2026 Board Hearing.

At this time, we cannot predict the potential future actions that may result from these orders or how such actions might potentially impact our operations.

On September 19, 2025, Governor Gavin Newsom signed SB 237 into law, which became effective on January 1, 2026. SB 237 added requirements to the California Government Code that provide that an existing oil pipeline that has been idle, inactive, or out of service for five years or more, cannot be restarted without passing a spike hydrostatic testing program. SB 237 also amended the California Coastal Act to provide that the repair, reactivation, or maintenance of an oil pipeline that has been idled, inactive or out of service for five years or more must obtain a new coastal development permit. On September 29, 2025, Sable filed a Complaint for Declaratory Relief against the State of California in Kern County Superior Court seeking a declaratory judgment that Pipeline Segments 324 and 325 are not subject to SB 237 because the Santa Ynez Pipeline System is not “idle, inactive, or out of service,” and because the Legislature did not give SB 237 retroactive effect. On January 21, 2026, the Company filed its First Amended Complaint adding a claim that the application of SB 237 to the Santa Ynez Pipeline System is preempted by federal law. On February 20, 2026, the State of California removed the case to the U.S. District Court for the Eastern District of California. Sable intends to continue to vigorously prosecute the action.

On June 3, 2022, the U.S. Court of Appeals for the Ninth Circuit prohibited the federal government from issuing new permits or plans for the use of well stimulation treatments, including hydraulic fracturing and acidizing of wells, in federal

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waters on the Pacific Outer Continental Shelf until a full environmental review is completed by federal agencies, including an environmental impact statement. The injunction was the result of lawsuits filed by the State of California, the California Coastal Commission and environmental groups alleging that federal agencies violated environmental laws when they authorized unconventional drilling methods from offshore California platforms. The court further found that the agencies violated the Endangered Species Act and Coastal Zone Management Act by not undertaking the appropriate consultations pursuant to those statutes.

While currently none of our Pacific Outer Continental Shelf operations rely on hydraulic fracturing stimulation or acidizing of wells as discussed in the Ninth Circuit decision, any restrictions on the future use of those well stimulation treatments or other forms of injection may adversely impact our operations, including causing operational delays, increased costs, and reduced production, which could adversely affect our revenues, results of operations and net cash provided by operating activities.

In December 2023, the State Lands Commission granted authority to the Executive Officer to solicit and execute agreements for consultant services to prepare an “Analysis of Public Trust Resources and Values” (“APTR”), which will assess the risks and impacts to Public Trust resources of all 12 leases for offshore oil and gas pipelines under the Commission’s jurisdiction. The APTR will include technical evaluations, environmental assessments, climate change considerations, public needs analysis, and alternatives to pipelines. The Commission expects to finalize the APTR by December 31, 2026. The Commission has also authorized a temporary moratorium on new lease applications and issuances for offshore oil and gas pipelines until the APTR is completed and its findings are reviewed. The outcome of the APTR could adversely affect our ability to renew or extend our State Lands Commission leases beyond the current expirations in 2028 and 2029.

On January 13, 2026, in response to the federal Department of the Interior’s proposed 11th (2026-2031) National Outer Continental Shelf Oil and Gas Leasing Program, California State Senate Member John Laird introduced Senate Joint Resolution 12 (“SJR 12”) to the California State Legislature. If passed as proposed, SJR 12 would state the California Legislature’s opposition to new offshore drilling, and support for the current federal prohibition on new oil or gas drilling, in federal waters offshore of the Pacific coast. SJR 12 also would request, on behalf of the California Legislature, that BOEM hold public hearings and prepare a programmatic environmental impact statement pursuant to the National Environmental Policy Act with respect to the proposed National Continental Shelf Oil and Gas Leasing Program. Although our existing offshore leases in federal waters would not directly be affected by the 11th National Outer Continent Shelf Oil and Gas Leasing Program or SJR 12, SJR 12 could be indicative of the Legislature’s general opposition to oil and gas leases off the California coast.

Our assets are located exclusively onshore and offshore in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.

We operate exclusively in California and in the federally-administered waters off the coast of California. This geographic concentration disproportionately affects the success and profitability of our operations, exposing us to local price fluctuations, changes in state or regional laws and regulations, political risks, limited acquisition opportunities where we have the most operating experience and infrastructure, limited storage options, drought conditions, and other regional supply and demand factors, including gathering, pipeline and transportation capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. We discuss such specific risks to our operations in more detail elsewhere in this section. In addition, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses.

All of our operations are conducted in areas that may be at risk of damage from fire, mudslides, earthquakes or other natural disasters.

We currently conduct operations in California and adjacent offshore areas near known wildfire and mudslide areas and earthquake fault zones. A future natural disaster, such as a fire, mudslide or an earthquake, could cause substantial interruption and delays in our operations, damage or destroy equipment, prevent or delay transport of our products and cause us to incur additional expenses, which would adversely affect our business, financial condition and results of operations. In addition, our facilities would be difficult to replace and would require substantial lead time to repair or replace. These events could occur with greater frequency as a result of the potential impacts from climate change. The insurance we maintain against earthquakes, mudslides, fires and other natural disasters would not be adequate to cover a total loss of our facilities, may not be adequate to cover our losses in any particular case and may not continue to be available to us on acceptable terms, or at all.

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Increasing attention to environmental, social and governance (“ESG”) matters may impact our business.

Increasing attention to, and social expectations on companies to address, climate change and other environmental and social impacts, investor and societal explanations regarding voluntary ESG disclosures, and increased consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we do meet such targets through operational changes, they may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us or our customers and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital. Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations.

Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.

Environmental groups may initiate litigation and take other actions to delay or prevent us from obtaining or maintaining required approvals to recommence oil sales.

Environmental groups have had increasing success in limiting oil and gas production by appealing to regulatory agencies, filing lawsuits and applying political pressure. In order to recommence oil sales we are required to obtain and maintain a series of permits or regulatory approvals from, among other agencies, PHMSA and BOEM. The laws and procedures governing these and other permits and regulatory approvals often allow third parties, including environmental groups, to challenge the draft permits and/or permit approvals through the relevant agencies and other administrative appeal processes. These groups may also file lawsuits that delay or prevent the issuance of the approvals through an injunction and/or prevailing on the legal merits or a ruling that additional approval is required. See “ Item 1. Business ” and Note 8 — Commitments and Contingencies for recent events. In addition, these groups may leverage the increased public attention and concern with respect to climate change and other environmental and social impacts in order to encourage government officials to withhold or delay the necessary approvals or require additional approvals. There is no assurance that these groups will not be successful in delaying or preventing us from obtaining or maintaining the required approvals through litigation or other actions.

The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and will impose new costs on our operations.

On August 16, 2022, President Biden signed into law the IRA. The IRA contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting

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infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower-or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA amends the Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the petroleum and natural gas production category. The methane emissions charge started in calendar year 2024 at $900 per ton of methane, has increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year thereafter. Calculation of the fee is based on certain thresholds established in the IRA. On November 18, 2024, the EPA published a final rule to implement this waste emissions charge as required by the IRA. However, on March 14, 2025, Congress through a joint resolution Congressional Review Act disapproved EPA’s final rule, and EPA removed the implementing regulations in May 2025. Subsequently, Congress amended the Clean Air Act in July 2025 to delay the start of this methane emissions charge until emissions reported for calendar year 2034 and to constrain EPA’s implementation authority and funding for that program. The methane emissions charge could increase our capital expenditures to limit methane releases and further increase our costs to the extent we exceed the limits, which may adversely affect our business and results of operations.

The cost of decommissioning and the cost of financial assurance to satisfy decommissioning obligations are uncertain.

We are required to maintain reserve funds to provide for the payment of decommissioning costs associated with our properties. The estimates of decommissioning costs are inherently imprecise and subject to change due to changing cost estimates, oil and natural gas prices and other factors. If actual decommissioning costs exceed such estimates, or we are required to provide a significant amount of collateral in cash or other security as a result of a revision to such estimates, our financial condition, results of operations and cash flows may be materially adversely affected.

We may be required to post cash collateral pursuant to our agreements with sureties, letter of credit providers or regulators under our existing or future bonding or other arrangements, which may have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan and our asset retirement obligation plan and comply with the agreements governing our existing or future indebtedness.

Pursuant to the terms of our existing bonding arrangements with various sureties in connection with the decommissioning obligations and government-mandated financial assurance obligations related to our properties, or under any future bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the sureties’ sole discretion. If additional collateral is required to support surety bond obligations, this collateral would probably be in the form of cash or letters of credit, certificates of deposit or other similar forms of liquid collateral. Letter of credit providers would also in turn likely expect collateral to support such obligations, primarily in the form of cash or other liquid collateral.

If sureties become unwilling to enter into or continue bonding arrangements with us, regulators would likely require us to post additional collateral or fully fund our obligations with cash or other forms of liquid collateral. We cannot provide any assurance that we will be able to satisfy collateral demands for current or future bonds or letters of credit, or that we will be able to satisfy funding requirements for other arrangements with regulators. If we are required to provide additional collateral or fully fund these obligations and we cannot obtain alternative financing, our liquidity position may be negatively impacted and we may be forced to reduce our capital expenditures in the current year or future years, may be unable to execute our asset retirement obligation plan or may be unable to comply with the agreements governing our existing or future indebtedness.

Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.

As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. There can be no assurance that our cybersecurity risk management program and processes, including our policies, controls or procedures, will be fully implemented, complied with or effective in protecting our systems and information. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could

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lead to losses of financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.

Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.

Risks Related to Being a Public Company

The market prices of our securities could be highly volatile or may decline regardless of our operating performance. You may lose some or all of your investment.

The trading price of our Common Stock is likely to be volatile and subject to significant fluctuations. The trading price of our Common Stock will depend on many factors, including those described in this “Risk Factors” section, many of which are beyond our control and may not be related to our operating performance. You may not be able to resell your shares at an attractive price due to a number of factors, such as the following:

• actual or anticipated fluctuations in our annual or quarterly financial results or the financial results of companies perceived to be similar to ours;

• changes in the market’s expectations about our operating results;

• the public’s reaction to our press releases, other public announcements and filings with the SEC;

• speculation in the press or investment community;

• actual or anticipated developments in our business, competitors’ businesses or the competitive landscape generally;

• our success in satisfying permitting and other regulatory requirements to resume full production;

• our success in satisfying permitting and other regulatory requirements to resume petroleum transportation through Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System or obtain alternate transportation;

• our ability to obtain water, drilling fluids and other critical resources;

• the accuracy of our assumptions and estimates regarding the total costs associated with resuming and maintaining production and the Santa Ynez Pipeline System;

• the market prices of oil, natural gas and NGL;

• the success of our hedging strategy;

• our ability to manage the safety risks associated with offshore development and production;

• our success in retaining or recruiting, or changes required in, our officers, key employees or directors;

• future laws and regulations related to climate change, GHGs and ESG and administrative interpretations thereof;

• changes in the future operating results of the Company;

• operating and stock price performance of other companies that investors deem comparable to ours;

• changes in laws and regulations affecting our business;

• commencement of, or involvement in, litigation involving the Company;

• changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;

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• the volume of our Common Stock available for public sale;

• any major change in our Board or management;

• sales of substantial amounts of our Common Stock by our directors, officers or significant stockholders or the perception that such sales could occur; and

• other risk factors and other matters described or referenced under the sections “ Risk Factors ” and “ Cautionary Note Regarding Forward‑Looking Statements .”

Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and the NYSE have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our securities, may not be predictable. A loss of investor confidence in the market for the stocks of other companies which investors perceive to be similar to ours could depress our Common Stock price regardless of our business, prospects, financial conditions or results of operations.

In addition, in the past, following periods of volatility in the overall market and the market prices of particular companies’ securities, securities class action litigations have often been instituted against these companies. Litigation of this type, if instituted against us, could result in substantial costs and a diversion of our management’s attention and resources. Any adverse determination in any such litigation or any amounts paid to settle any such actual or threatened litigation could require that we make significant payments.

Our stock price may be exposed to additional risks because we became a public company through a “de‑SPAC” transaction. There has been increased focus by government agencies on such transactions, and we expect that increased focus to continue, and we may be subject to increased scrutiny by the SEC and other government agencies on holders of our securities as a result, which could adversely affect the price of our Common Stock.

We are, and may continue to be, subject to short selling strategies and related public allegations, which could lead to a decline in the price of our Common Stock and have a material adverse effect on our reputation and results of operations.

Short selling is the practice of selling securities that the seller does not own but rather has borrowed from a third party with the intention of buying identical securities back at a later date to return to the lender. The short seller hopes to profit from a decline in the value of the securities between the sale of the borrowed securities and the purchase of the replacement shares, as the short seller expects to pay less in that purchase than it received in the sale. To facilitate the decline in stock price, short sellers may engage in strategies to publish, or arrange for the publication of, opinions regarding the relevant issuer and its business prospects to create negative market momentum and generate profits for themselves after selling a stock short. Such short selling strategies have resulted in considerable selling of the targeted issuer’s shares in the market.

We are, and may in the future may be, the subject of unfavorable allegations made by short sellers. For example, on October 31, 2025, Hunterbrook Media issued a report to short sellers that contained certain allegations against us. In response, our Board of Directors formed a special committee to oversee an independent investigation of the matters referenced in the report. The investigation is ongoing and we may or may not uncover additional material information as the investigation moves forward. As a result, we are unable to predict the outcome or to reasonably estimate the time or expense it may take to resolve these matters.

We may, in the future, become subject to additional unfavorable reports. Any such allegations may be followed by periods of instability in the market price of our shares of Common Stock and negative publicity. Any related inquiry or formal investigation from a governmental organization or other regulatory body, or resulting litigation from private claimants, could result in a material diversion of our management’s time and could have a material adverse effect on our business and results of operations. Such a situation could be costly and time-consuming and could distract our management from operating our business.

We are subject to an ongoing investigation by a Special Committee of the Board and have received subpoenas for documents from the SDNY and SEC, and may be named in future governmental or other regulatory investigations and proceedings, each of which could have a material adverse impact on our business, financial condition, results of operation, cash flows and reputation.

As announced on November 3, 2025, the members of the Board formed a special committee of independent directors (the “Special Committee”) to undertake an independent investigation of the allegations contained in the Hunterbrook Report.

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The Special Committee’s investigation remains underway. In addition, the Company has received subpoenas for documents from the SDNY and SEC (the “Government Requests”).

The Special Committee investigation and Government Requests could each have an adverse impact on the Company. We cannot predict or provide any assurance as to the timing, outcome or consequences of the Special Committee investigation or the Government Requests. If the SEC or SDNY were to conclude that an enforcement action is appropriate, the SEC could impose civil penalties and fines, and other sanctions against us or against our current and former officers and directors, and the SDNY could impose criminal penalties. We may incur significant expenses related to legal and other professional services in connection with matters relating to or arising from the Special Committee investigation or the Government Requests. These cash outflows may negatively impact our cash position and profitability. We cannot predict if the government will impose any penalty or fine and, if it does, the magnitude or timing of such penalty or fine; however, any penalty or fine would also negatively impact our cash position, profitability, and liquidity.

In addition, our Board, management and employees have expended, and may continue to expend, a substantial amount of time on the Special Committee investigation and the Government Requests, diverting resources and attention that would otherwise be directed toward our operations and implementation of our business strategy, all of which could materially adversely affect our business, financial condition and results of operations. Publicity surrounding the foregoing, or any enforcement action or settlement as a result of the Government Requests, even if ultimately resolved favorably for us, could have an adverse impact on our reputation, business, financial condition, and results of operations.

In addition, we could be subject to future claims, investigations, or proceedings. Any future inquiries from regulatory authorities, or future claims or proceedings as a result of the Special Committee investigation, the Government Requests or related regulatory investigations, will, regardless of the outcome, consume a significant amount of our internal resources and result in additional legal and accounting costs.

The NYSE may not continue to list our securities, which could limit investors’ ability to make transactions in our securities and subject us to additional trading restrictions.

We cannot assure you that our securities will continue to be listed on the NYSE in the future. In order for our securities to remain listed on the NYSE, we must maintain certain financial, distribution and stock price levels.

If the NYSE delists our securities from trading on its exchange and we are not able to list our securities on another national securities exchange, we expect our securities could be quoted on an over‑the‑counter market. If this were to occur, we could face significant material adverse consequences, including:

• a limited availability of market quotations for our securities;

• reduced liquidity for our securities;

• a determination that our Common Stock is a “penny stock,” which would require brokers trading in such securities to adhere to more stringent rules, could adversely impact the value of our securities and/ or possibly result in a reduced level of trading activity in the secondary trading market for our securities;

• a limited amount of news and analyst coverage; and

• a decreased ability to issue additional securities or obtain additional financing in the future.

If we fail to implement and maintain proper and effective internal controls over financial reporting, our ability to produce accurate financial statements on a timely basis could be impaired, which could cause investors to lose confidence in our reported financial information and have a negative effect on our stock price.

Ensuring that we have adequate internal financial and accounting controls and procedures in place to produce accurate financial statements on a timely basis is a costly and time-consuming effort that needs to be reevaluated frequently. Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”). A control, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control’s objectives will be met. Because of the inherent limitations in all controls, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, within our company will have been detected. Effective internal controls are necessary for us to produce reliable financial reports and are important to prevent fraud. Any failure to maintain or implement new or improved controls over financial reporting

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could result in material weaknesses or result in the failure to detect or prevent material misstatements in our financial statements, which could cause investors to lose confidence in our reported financial information and harm our stock price.

Future sales, or the perception of future sales, of our Common Stock by us or our existing stockholders in the public market could cause the market price for our Common Stock to decline.

The sale of substantial amounts of shares of our Common Stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our Common Stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

Shares held by certain of our stockholders will be eligible for resale, subject to, in the case of certain stockholders, volume, manner of sale and other limitations under Rule 144. In addition, pursuant to the Registration Rights Agreement entered into by and among Sable and certain stockholders party thereto, such stockholders will be entitled to customary registration rights for 3,000,000 shares of our Common Stock following their respective lock-up periods. The sale or possibility of sale of these securities could have the effect of increasing the volatility in our share price or putting significant downward pressure on the price of our Common Stock.

Our issuance of additional shares of Common Stock or convertible securities may dilute your ownership of us and could adversely affect our stock price.

We filed a registration statement on Form S-8 on April 19, 2024 providing for the registration of shares of our Common Stock issued or reserved for issuance under the Sable Offshore Corp. 2023 Incentive Award Plan (the “ Incentive Plan ”). The Incentive Plan provides for automatic increases in the shares reserved for grant or issuance under the plan which could result in additional dilution to our stockholders. Subject to the satisfaction of vesting conditions and the expiration of any applicable lockup restrictions, shares registered under the registration statement on Form S-8 will generally be available for resale immediately in the public market without restriction. From time to time in the future, we may also issue additional shares of our Common Stock or securities convertible into our Common Stock pursuant to a variety of transactions, including acquisitions. The issuance by us of additional shares of our Common Stock or securities convertible into our Common Stock would dilute your ownership of us and the sale of a significant amount of such shares in the public market could adversely affect prevailing market prices of our Common Stock.

In the future, we may seek to obtain financing or to further increase our capital resources by issuing additional shares of our capital stock or offering debt or other equity securities, including senior or subordinated notes, debt securities convertible into equity, or shares of preferred stock. Issuing additional shares of our capital stock, other equity securities, or securities convertible into equity may dilute the economic and voting rights of our existing stockholders, reduce the market price of our Common Stock, or both. Debt securities convertible into equity could be subject to adjustments in the conversion ratio pursuant to which certain events may increase the number of equity securities issuable upon conversion. Preferred stock, if issued, could have a preference with respect to liquidating distributions or a preference with respect to dividend payments that could limit our ability to pay dividends to the holders of our Common Stock. Our decision to issue securities in any future offering will depend on market conditions and other factors beyond our control, which may adversely affect the amount, timing or nature of our future offerings. As a result, holders of our Common Stock bear the risk that our future offerings may reduce the market price of our Common Stock and dilute their percentage ownership.

Our warrant agreement designates the courts of the State of New York or the United States District Court for the Southern District of New York as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by holders of our warrants, which could limit the ability of Warrant Holders to obtain a favorable judicial forum for disputes with our company.

Our warrant agreement provides that, subject to applicable law, (i) any action, proceeding or claim against us arising out of or relating in any way to the warrant agreement, including under the Securities Act, will be brought and enforced in the courts of the State of New York or the United States District Court for the Southern District of New York, and (ii) that we irrevocably submit to such jurisdiction, which jurisdiction will be the exclusive forum for any such action, proceeding or claim. Under our warrant agreement, we also agree that we will waive any objection to such exclusive jurisdiction and that such courts represent an inconvenient forum.

Notwithstanding the foregoing, these provisions of the warrant agreement do not apply to suits brought to enforce any liability or duty created by the Exchange Act or any other claim for which the federal district courts of the United States of America are the sole and exclusive forum. Any person or entity purchasing or otherwise acquiring any interest in any of our warrants will be deemed to have notice of and to have consented to the forum provisions in our warrant agreement.

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If any action, the subject matter of which is within the scope of the forum provisions of the warrant agreement, is filed in a court other than a court of the State of New York or the United States District Court for the Southern District of New York (a “ foreign action ”) in the name of any holder of our warrants, such holder will be deemed to have consented to: (x) the personal jurisdiction of the state and federal courts located in the State of New York in connection with any action brought in any such court to enforce the forum provisions (an “ enforcement action ”), and (y) having service of process made upon such Warrant Holder in any such enforcement action by service upon such Warrant Holder’s counsel in the foreign action as agent for such Warrant Holder.

This choice-of-forum provision may limit a Warrant Holder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with our company, which may discourage such lawsuits. Alternatively, if a court were to find this provision of our warrant agreement inapplicable or unenforceable with respect to one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could materially and adversely affect our business, financial condition and results of operations and result in a diversion of the time and resources of our management and board of directors.

Members of our management team and our Board and their respective affiliated companies have been, and may from time to time be, involved in legal proceedings or governmental investigations unrelated to our business.

Members of our management team and our Board have been involved in a wide variety of businesses. Such involvement has, and may lead to, media coverage and public awareness. As a result of such involvement, members of our management team and our Board and their respective affiliated companies have been, and may from time to time be, involved in legal proceedings or governmental investigations unrelated to our business. Any such proceedings or investigations may be detrimental to our reputation and could negatively affect our ability to identify and complete an initial business combination and may have an adverse effect on the price of our securities.

If securities or industry analysts do not publish research or reports about us, or publish negative reports, our stock price and trading volume could decline.

The trading market for our Common Stock will depend, in part, on the research and reports that securities or industry analysts publish about us. We will not have any control over these analysts. If our financial performance fails to meet analyst estimates or one or more of the analysts who cover us downgrade our Common Stock or change their opinion, our stock price would likely decline. If one or more of these analysts cease coverage of us or fail to regularly publish reports on us, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.

Our operating results may fluctuate significantly, which makes our future operating results difficult to predict and could cause our operating results to fall below expectations or any guidance it may provide.

Our quarterly and annual operating results may fluctuate significantly, which makes it difficult for us to predict our future operating results. These fluctuations may occur due to a variety of factors, many of which are outside of our control, including, but not limited to:

• the costs associated with maintaining production and the Santa Ynez Pipeline System;

• the market prices of oil, natural gas and NGL;

• the success of our hedging strategy;

• future accounting pronouncements or changes in our accounting policies;

• macroeconomic conditions, both nationally and locally; and

• any other change in the competitive landscape of our industry, including consolidation among our competitors or partners.

The cumulative effects of these factors could result in large fluctuations and unpredictability in our quarterly and annual operating results. As a result, comparing our operating results on a period‑to‑period basis may not be meaningful. Investors should not rely on past results as an indication of future performance. This variability and unpredictability could also result in us failing to meet the expectations of industry or financial analysts or investors for any period. If our revenue or operating results fall below the expectations of analysts or investors or below any forecasts we may provide to the market, or if the forecasts we provide to the market are below the expectations of analysts or investors, the price of our Common

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Stock could decline substantially. Such a stock price decline could occur even when we have met any previously publicly stated revenue or earnings guidance we may provide.

Changes in laws, regulations or rules, or a failure to comply with any laws, regulations or rules, may adversely affect our business, investments and results of operations.

We are subject to laws, regulations and rules enacted by national, regional and local governments and the NYSE. In particular, We are required to comply with certain SEC, NYSE and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Such laws, regulations or rules and their interpretation and application may also change from time to time and such changes could have a material adverse effect on our business, investments and results of operations. In addition, any failure by us to comply with applicable laws, regulations or rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.

We no longer qualify as an “emerging growth company” and will be required to comply with certain provisions of the Sarbanes-Oxley Act. We can no longer take advantage of reduced disclosure requirements applicable to emerging growth companies.

Based on the market value of our common stock held by non-affiliates as of June 30, 2025, we no longer qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”), as of December 31, 2025. As a result, we may incur additional and increasing costs to comply with our reporting and other obligations that we had not historically incurred due to our status as an emerging growth company or as a smaller reporting company. These costs include (i) being required to comply with the auditor attestation requirements of Section 404, (ii) increased disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and (iii) requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. These additional obligations will require us to dedicate internal resources, engage outside consultants, and adopt a detailed work plan to assess and document the adequacy of internal controls over financial reporting, continue steps to improve control processes, as appropriate, validate through testing that controls are functioning as documented, and implement a continuous reporting and improvement process for internal controls over financial reporting.

Because there are no current plans to pay cash dividends on our Common Stock in the foreseeable future, you may not receive any return on investment unless you sell your shares of our Common Stock at a price greater than what you paid for it.

We intend to retain future earnings, if any, for future operations, expansion and debt repayment and there are no current plans (at least until the resumption of full production at SYU and the repayment or refinancing of the Senior Secured Term Loan) to pay any cash dividends in the near term. The declaration, amount and payment of any future dividends on shares of our Common Stock will be at the sole discretion of our Board and subject to restrictions and limitations in the Senior Secured Term Loan or any other then‑existing indebtedness of the Company. Our Board may take into account general and economic conditions, our financial condition and results of operations, our available cash and current and anticipated cash needs, capital requirements, contractual, legal, tax and regulatory restrictions, implications of the payment of dividends by us to our stockholders or by our subsidiaries to us and such other factors as our Board may deem relevant. As a result, you may not receive any return on an investment in our Common Stock unless you sell your shares of our Common Stock for a price greater than that which you paid for it.

ITEM 7.      MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto in Item 8. Financial Statements and Supplementary Data of this report. In addition to historical data, this discussion contains forward-looking statements about our business, operations and financial performance based on current expectations that involve risks, uncertainties and assumptions. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including but not limited to those discussed in “ Cautionary Note Regarding Forward-Looking Statements ” and Part I, Item 1A. “ Risk Factors .”

A discussion of the year ended December 31, 2024, compared to the year ended December 31, 2023, has been reported previously under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 17, 2025.

Overview

We are a Houston-based independent upstream company focused on responsibly developing the Santa Ynez Unit in federal waters offshore California. Our team has decades of experience safely operating in California and creating value for stakeholders. We have one reportable segment, the oil and gas segment, refer to Note 1 — Organization, and Business Operations and Going Concern and Note 2 — Significa nt Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for further discussion.

For the purposes of this discussion, periods on or before February 13, 2024 reflect the financial position, results of operations and cash flows of SYU prior to the Business Combination, referred to herein as the “Predecessor,” and periods beginning on or after February 14, 2024 reflect the financial position, results of operations and cash flows of the Company as a result of the Business Combination, referred to herein as the “Successor.”

2025 Operational and Financial Highlights

• On May 19, 2025, we announced that (i) as of May 15, 2025, we had restarted production at the Santa Ynez Unit and begun flowing oil production to Las Flores Canyon and (ii) we completed our anomaly repair program on Pipeline Segments 324 and 325 of the Santa Ynez Pipeline System as specified by the Consent Decree.

• On May 23, 2025, we closed an upsized underwritten public offering of 10,000,000 shares of Common Stock at a public offering price of $29.50 per share. The gross proceeds from the offering, before deducting discounts and commissions and estimated expenses, were approximately $295.0 million.

• On May 28, 2025, we announced that we successfully completed hydrotests of all segments of the Santa Ynez Pipeline System, satisfying the final operational condition to resume petroleum transportation through Pipeline Segments 324 and 325 as outlined in the Consent Decree.

• As an alternative to the Santa Ynez Pipeline System, we announced that we are also pursuing an OS&T strategy to provide access to domestic and global markets via shuttle tankers for federal crude oil produced from the Santa Ynez Unit in the Pacific Outer Continental Shelf Area.

• On November 10, 2025, we entered into subscription agreements to issue 45,454,546 shares of Common Stock in a private placement to institutional investors at a purchase price of $5.50 per share, raising $250.0 million in gross proceeds.

• On November 24, 2025, we satisfied all conditions to effectiveness of the Second Amendment to the Senior Secured Term Loan, thereby extending the maturity date of the Senior Secured Term Loan to the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of hydrocarbons. The Second Amendment increased the interest rate from ten percent (10%) per annum to fifteen percent (15%) per annum, compounded annually.

• On December 17, 2025, PHMSA notified us that it concurred with our determination that the Santa Ynez Pipeline System is an interstate pipeline facility under the Pipeline Safety Act, pursuant to which PHMSA is vested with exclusive regulatory authority over interstate pipelines. In its notification, PHMSA additionally states that it considers the Santa Ynez Pipeline System to be an “active” pipeline according to PHMSA regulations.

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• On December 23, 2025, PHMSA issued an emergency special permit for segments of the interstate Santa Ynez Pipeline System (specifically Pipeline Segments 324 and 325), related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325.

• We reported a net loss of $410.2 million, primarily attributable to production restart related operating expenses, general & administrative expenses, and non-cash interest expense, partially offset by a non-cash change in fair value of warrant liabilities.

• We ended the year with short-term outstanding debt of $921.6 million, inclusive of paid-in-kind interest, and a cash and cash equivalents balance of $97.7 million.

SYU Assets

Beginning in 1968 and over the course of 14 years, EM consolidated more than a dozen offshore federal oil leases and organized them into a streamlined production unit known as the SYU. The SYU remained in continuous operation until 2015. In May 2015, Pipeline Segment 324 (then known as “Line 901”) experienced a leak while operated by Plains. The SYU suspended production after the Line 901 incident and the facilities were maintained in a safe state. On May 19, 2025, the Company announced that as of May 15, 2025, it had restarted production at the SYU and begun flowing oil production from six wells at SYU’s Platform Harmony to the Company’s storage and processing facilities at LFC.

Prior to May 15, 2025, the SYU had not produced oil and gas since May 2015; however, all equipment remained in place in an operation-ready state, requiring ongoing inspections, maintenance and surveillance. As part of these efforts, all equipment was drained, flushed and purged in 2016. The Santa Ynez Pipeline System was maintained in a safe state and regularly monitored.

The discussion of the results of operations for the Predecessor periods below do not include the results from the Pipeline Segments 324 and 325, and the Pipeline Segments 324 and 325 are not included in the combined financial statements of the Predecessor included in the financial statements and related notes thereto included elsewhere in this Annual Report. Financial statements of the Pipeline Segments 324 and 325 have not been included because SEC guidance provides that the financial statements of recently acquired businesses such as the Pipeline Segments 324 and 325 need not be filed unless their omission would render Predecessors combined financial statements misleading or substantially incomplete. Based upon our quantitative and qualitative analysis, we do not believe omitting the financial statements of the Pipeline Segments 324 and 325 renders the Predecessor combined financial statements misleading or substantially incomplete. The Successor financial statements include the results from the Pipeline Segments 324 and 325 and the Pipeline Segments 324 and 325 are included in the consolidated financial statements.

Outlook

The future operating and financial performance of the Company is expected to be driven primarily by our ability to establish a lawful, reliable, and economic pathway to market crude oil and natural gas produced from the SYU, resume sustained offshore production, and manage regulatory, legal, and commodity price risks associated with its federal offshore and California onshore and offshore assets.

Recommencing Oil Sales

Our near-term outlook is highly dependent on our ability to recommence oil transportation through the Santa Ynez Pipeline System. As previously noted, PHMSA confirmed that the Santa Ynez Pipeline System is classified as active interstate pipeline subject to federal jurisdiction under the Pipeline Safety Act. Additionally, we received an Emergency Special Permit from PHMSA related to cathodic protection and seam weld corrosion along Pipeline Segments 324 and 325. This permit is conditional in nature and requires ongoing compliance with specified operational and reporting obligations, including enhanced integrity management, inspection, testing, and monitoring requirements. The emergency special permit expired on February 21, 2026. By letter dated February 13, 2026 to PHMSA, the Company committed to continued compliance with the conditions of the emergency special permit until PHMSA makes a determination on the Company’s application for Special Permit (which was submitted on January 22, 2026).

On December 31, 2025, the U.S. Court of Appeals for the Ninth Circuit denied a motion to stay PHMSA’s approvals of the Company’s Restart Plan and Emergency Special Permit, allowing those approvals to remain in effect during the pendency of the appeal. While the appeal remains ongoing, the Company may continue to advance activities related to resuming petroleum transportation through Pipeline Segments 324 and 325, subject to satisfaction of all applicable regulatory, operational, and commercial requirements.

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On January 23, 2026, a second petition was filed in the U.S. Court of Appeals for the Ninth Circuit by the State of California, also against the U.S. Department of Transportation; Sean Duffy, in his official capacity as Secretary of the U.S. Department of Transportation; PHMSA; and Paul Roberti, in his official capacity as Administrator of PHMSA. The second petition, filed by the State of California, Attorney General and OSFM, challenges the Emergency Special Permit, but also challenges PHMSA’s assertion of jurisdiction over the Santa Ynez Pipeline System.

We cannot generate material oil sales without a functioning transportation solution. As a result, any delay, suspension, or revocation of PHMSA’s approvals, or any operational issue encountered during commissioning Pipeline Segments 324 and 325, could materially delay the resumption of commercial oil sales and adversely affect future revenues and cash flows. “Risk Factors—We are subject to complex federal, state, local and other laws, regulations and permits that could adversely affect the cost, manner, ability or feasibility of conducting our operations.”

Offshore Storage and Treating Vessel (OS&T) Alternative

In parallel with pursuing oil sales via Santa Ynez Pipeline System, we continue to evaluate an OS&T vessel as a potential alternative pathway to market crude oil. Under this concept, produced fluids would be processed offshore, stored on a floating vessel, and periodically offloaded to shuttle tankers for delivery to third-party purchasers.

The OS&T Strategy is significantly more capital-intensive than the Santa Ynez Pipeline System, requiring an estimated capital investment of approximately $475.0 million, inclusive of vessel acquisition, configuration, offshore integration, regulatory compliance, and related infrastructure. Based on current assessments, we do not expect to commence commercial oil sales under an OS&T Strategy until approximately the fourth quarter of 2026, assuming timely execution, regulatory approvals, and availability of capital.

While the OS&T Strategy could reduce reliance on the Santa Ynez Pipeline System, which may enhance our marketing strategy going forward by providing flexibility to sell production to additional purchasers through the OS&T rather than being limited to a purchaser under a pipeline-only sales configuration, it presents substantial execution, financing, regulatory, and operational risks. These risks include vessel availability, permitting complexity, higher operating costs, exposure to marine operational risks, and uncertainty regarding the economic returns relative to pipeline transportation. We have not made a final investment decision with respect to an OS&T vessel, and there can be no assurance that such a project would be pursued, financed, or completed on acceptable terms, if at all. See “ Risk Factors—Risks Associated with Our Operations—In order to commence operations pursuant to an OS&T offtake strategy, we will require clearances and permitting, including from BOEM ” and “ Risk Factors—Risks Associated with Our Operations—Our assumptions and estimates regarding the total costs associated with recommencing oil sales may be inaccurate. ”

Legal and Regulatory Environment

The Company’s assets are located in California, a jurisdiction with a complex regulatory framework and heightened environmental oversight. PHMSA’s approvals related to the Santa Ynez Pipeline System have been challenged by third parties through litigation, and the outcome of such proceedings is uncertain. Adverse court rulings, including the issuance of injunctions or stays, could delay or prevent pipeline operations regardless of the Company’s technical readiness.

In addition to federal oversight, the Company remains subject to state and local regulatory agencies, including the California Geologic Energy Management Division and other environmental and land-use authorities. While these agencies do not directly regulate interstate pipeline safety, their actions may affect related permits, inspections, or operational approvals, which could influence the timing, cost, or feasibility of both pipeline and OS&T-based solutions.

We are involved in various legal and regulatory proceedings, including matters related to our pipeline operations and permitting activities, which are at various stages of resolution; while these matters are subject to inherent uncertainty, we currently believe that the outcomes are not probable of resulting in a material loss and, accordingly, no litigation-related accruals have been recorded as of the reporting date. Refer to Part II, Item 8, “ Financial Statements and Supplementary Data – Notes to the Consolidated Financial Statements, Note 8 — Commitments and Contingencies ” for further information regarding ongoing litigation.

Production Ramp-Up and Operational Execution

Assuming a transportation solution is established, our future performance will depend on our ability to safely ramp up offshore production, manage operating costs, and maintain asset integrity following an extended period of curtailed operations. Restarting production from offshore facilities involves inherent operational risks, including mechanical failures, unplanned downtime, and higher-than-expected maintenance or remediation costs, any of which could adversely affect production volumes and operating margins.

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Capital and Financing Requirements

Until sustained commercial oil sales are achieved, our liquidity will depend on available cash balances, access to raise additional capital from investors, and the timing of expenditures related to regulatory compliance, litigation, offshore facility maintenance, and potential alternative transportation solutions. The OS&T vessel alternative, in particular, would require substantial external financing or strategic arrangements and could materially increase our leverage or dilution. There can be no assurance that such financing would be available on acceptable terms, or at all.

Capital Expenditures. During 2025, we funded $417.6 million in development and other property, plant and equipment expenditures primarily by utilizing net cash provided by our financing activities and cash on hand.

We currently estimate no remaining start-up expenses to recommence oil sales via the Santa Ynez Pipeline System, other than applicable legal expenses. Upon resuming petroleum transportation through the Santa Ynez Pipeline System, we anticipate approximately $100.0 million to $200.0 million in additional post-sales capital expenditures for 2026, primarily related to facilities, pipeline ramp-up activities, and other property, plant and equipment, depending on timing and excluding any OS&T-related capital expenditures. Alternatively, if we elect to pursue the OS&T Strategy, total anticipated 2026 capital expenditures are estimated to be approximately $475.0 million, including costs to acquire and purchase the vessel in addition to incremental investments associated with related infrastructure. Depending on the timing and outcome of regulatory approvals and the execution of commercial arrangements, we could incur capital expenditures beyond these ranges. We cannot provide any assurances that our assumptions used to estimate our liquidity requirements, our anticipated cost savings or reductions, or the costs required to achieve operations under the OS&T Strategy will be correct, as we have not previously undertaken such actions and as a consequence, our ability to predict such amounts is uncertain and may be impacted by factors outside of our control.

Debt Financing. As of December 31, 2025, we had gross indebtedness of $921.6 million outstanding under the Senior Secured Term Loan, (refer to Note 6 — Debt to the consolidated financial statements). On November 3, 2025, we entered into the Second Debt Amendment, which became effective on November 24, 2025 following the completion of the Third PIPE Investment and satisfaction of all conditions to effectiveness. Pursuant to the Second Debt Amendment, the maturity date of the Senior Secured Term Loan was extended to the earlier of (i) March 31, 2027 or (ii) 90 days after the Company’s first sales of hydrocarbons. In connection with the Second Debt Amendment, the interest rate on the Senior Secured Term Loan increased from ten percent (10.0%) per annum to fifteen percent (15.0%) per annum, computed on a 360-day year, compounded annually, and payable in arrears on January 1 of each year. Notwithstanding the maturity extension, the Senior Secured Term Loan is classified as a current liability on the Company’s consolidated balance sheet as of December 31, 2025 due to management’s expected maturity date based on anticipated first sales from SYU.

After we are able to recommence oil sales and improve our operating cash flows, we expect to pursue a refinancing of the Senior Secured Term Loan, which may include a new credit facility, term notes, or other debt capital market transactions. We believe that demonstrating sustained oil sales and cash flow generation in the future could improve our access to financing and potentially reduce our overall cost of capital. Any refinancing would be subject to market conditions, lender requirements, regulatory developments, and other factors outside our control. There can be no assurance that such a refinancing will be completed on favorable terms, or at all.

Components of Results of Operations

Revenue

The Company has not had any substantial revenues since its inception. The Company’s various operating expenses are the principal metrics used to assess its performance.

Operating Expenses

• Operations and maintenance. The Company’s most significant costs to operate and maintain its assets are direct labor and supervision, power, repair and maintenance expenses, and equipment rentals. Fluctuations in commodity prices impact operating cost elements both directly and indirectly. For example, commodity prices directly impact costs such as power and fuel, which are expenses that increase (or decrease) in line with changes in commodity prices. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as labor and equipment rentals.

• Depreciation, depletion, amortization, and accretion. Depreciation, depletion and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Since 2015 when production temporarily ceased, no depletion has been expensed for the Successor periods presented. However, depletion associated

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with the current production has been capitalized to Inventory for produced barrels in storage at SYU (see further discussion in Note 2 — Significant Accounting Policies to the consolidated financial statements). An immaterial amount of depreciation was reflected for idle plants in the historical Predecessor financial statements. Also included in the Successor and Predecessor financial statements is the accretion associated with the Company’s estimated asset retirement obligations (“ARO”). The ARO liabilities are initially recorded at their fair value and then are accreted using the Company’s applicable discount rate over the period for the change in their present value until the estimated retirement of the asset.

• General and administrative. General and administrative (“G&A”) costs are comprised of overhead expenditures directly and indirectly associated with operating the assets. These support services include information technology, risk management, corporate planning, accounting, cash management, human resources, and other general corporate services. For the Predecessor period, any general and administrative expenses that were not specifically identifiable to SYU were allocated to SYU for the period from January 1, 2024 to February 13, 2024. To calculate a reasonable allocation, aggregated historical benchmarking data from comparable companies with similar operated upstream assets was used to identify general and administrative expenses as a proportion of operating expenses. Increased general and administrative services may be required in the future, commensurate with planned operations activity levels.

• Taxes other than income. Management anticipates future increases in ad valorem taxes, in line with the projected restarting sales of production volumes.

Results of Operations

This section discusses certain year-to-year comparisons between year ended December 31, 2025 (Successor) vs. the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor), which should be read in conjunction with the consolidated financial statements and notes thereto in Item 8. Financial Statements and Supplementary Data of this report.

The following table presents selected consolidated financial results of operations for the Successor and Predecessor periods presented.

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Year Ended December 31, 2025 (Successor) vs. the periods from January 1, 2024 through February 13, 2024 (Predecessor) and February 14, 2024 through December 31, 2024 (Successor).

The following table presents selected consolidated financial results of operations for the Successor and Predecessor periods presented.

Successor

Predecessor

Increase (Decrease)

(in thousands)

Year Ended December 31, 2025

February 14—December 31, 2024

January 1—February 13, 2024

Revenue

Oil and gas sales

Total Revenue

Operating Expenses

Operations and maintenance expenses

Depletion, depreciation, amortization and accretion

General and administrative expenses

Total operating expenses

Loss from operations

Other (income) expenses:

Change in fair value of warrant liabilities

Other (income) expense

Interest expense

Total other (income) expense, net

Loss before income taxes

Income tax expense (benefit)

Net loss

nm: not meaningful

Operating and maintenance expenses. Operating and maintenance expenses were $219.2 million for the year ended December 31, 2025, representing an increase of $124.0 million, or 130%, compared to $7.3 million for the period from January 1, 2024 through February 13, 2024 (Predecessor) and $87.9 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $95.2 million. The increase in operating and maintenance expenses is primarily attributable to additional maintenance expenses incurred in connection with restart efforts, which includes a 37% increase in operations employee headcount since the prior year, $28.0 million related to operator rights expenditures, and $6.6 million related to restart incentive compensation, partially offset by $6.1 million of operating expense capitalized as Inventory on the consolidated balance sheet as of December 31, 2025. Operations and maintenance expenses are expected to remain elevated prior to our commencement of sales of production.

Depletion, depreciation, amortization and accretion. Depletion, depreciation, amortization and accretion was $12.9 million for the year ended December 31, 2025, representing an increase of $0.5 million, or 4%, compared to $2.6 million for the period January 1, 2024 through February 13, 2024 (Predecessor) and $9.7 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $12.4 million. The increase between comparative periods is attributable to ARO accretion and its compounding effect year over year. Depletion, depreciation and amortization of $6.0 million associated with the SYU Assets was recognized during the year ended December 31, 2025; however, as the associated production remained in the Company’s storage tanks as of December 31, 2025, the entire amount has been capitalized as Inventory on the consolidated balance sheet. Recognition of depletion expense will resume once sales volumes are achieved. Depletion, depreciation, amortization and accretion expense is expected to increase prior to our commencement of sales of production.

General and administrative expenses. G&A expenses were $176.2 million for the year ended December 31, 2025, representing a decrease of $54.7 million compared to $1.7 million for the period January 1, 2024 through February 13, 2024 (Predecessor) and $229.1 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $230.9 million. This decrease is primarily attributable to higher non-recurring G&A expenses recognized for the period February 14, 2024 through December 31, 2024 (Successor) such as the $70.0 million accrued

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settlement of the Grey Fox Matter (Refer to Note 8 — Commitments and Contingencies ) and $16.8 million in legal expenses and professional fees related to the Business Combination. Also contributing to the decrease in G&A expenses was a $49.0 million decrease in share-based compensation expense between reporting periods. These decreases were partially offset by $35.7 million in higher compensation related to restart incentive compensation costs, $29.7 million in higher legal expenses and professional fees attributable to our continued pursuit of achieving first sales, and the recognition of salaries and wages for the full year ended December 31, 2025, compared to the Successor period February 14, 2024 through December 31, 2024. Predecessor G&A expenses were allocated to SYU as a portion of certain other operating costs based on aggregated historical benchmarking data as previously noted (Refer to Note 2 — Significant Accounting Policies ) .

Total other (income) expense, net. Total other income, net was $9.8 million for the year ended December 31, 2025 compared to other expense, net of $0.1 million for the period January 1, 2024 through February 13, 2024 (Predecessor) and other expense of $290.6 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined expense of $290.7 million, representing a favorable year-over-year change of $300.5 million. The change in total other (income) expense, net was primarily attributable to a decrease of $316.7 million in the fair value of the warrants, due to fewer warrants outstanding for the year ended December 31, 2025 after all public warrants were redeemed during the year ended December 31, 2024, an increase in the market price of the Common Stock in the prior period compared to a decrease in the market price of the Common Stock in the current year, and a $4.8 million decrease in other (income) expense attributable to $5.0 million of other expense recognized during the period February 14, 2024 through December 31, 2024 (Successor) related to the First Amendment to the Senior Secured Term Loan (Refer to Note 6 — Debt for additional details regarding the First Amendment to the Senior Secured Term Loan), partially offset by $20.9 million in higher interest expense for the year ended December 31, 2025 due to higher debt balance over the comparative periods and the increased interest rate following the Second Debt Amendment (Refer to Note 6 — Debt for additional details regarding the Second Debt Amendment). The Predecessor did not have any debt or associated interest expense, warrants, or interest income.

Income tax expense (benefit). Income tax expense for the year ended December 31, 2025 was $11.7 million, representing an increase of $11.7 million compared to zero for the period January 1, 2024 through February 13, 2024 (Predecessor) and less than $0.1 million for the period February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined less than $0.1 million. Utilizing provisions of ASC 740, the Company’s effective tax rate was negative 2.9%, and less than negative 0.01% for the year ended December 31, 2025 and the period February 14, 2024 through December 31, 2024 (Successor) respectively. The negative tax rates were due to our ongoing assessment of our ability to recover our deferred tax assets, in which we concluded that it was more likely than not that our deferred tax assets in excess of deferred tax liabilities would not be realized. The negative income tax rate was greater for the year ended December 31, 2025 due to an increase in the valuation allowance primarily associated with net operating losses not expected to be realized in future periods.

Liquidity and Capital Resources

Overview. Our plans for recommencing sales of production volumes, including restarting the remainder of the existing wells and facilities that have not been restarted and recommencing oil transportation through the Santa Ynez Pipeline System or via OS&T, will require significant capital expenditures in excess of current operational cash flow. Historically, SYU’s primary source of liquidity has been its operational cash flow and, since 2015 when production temporarily ceased, capital contributions from its parent. While production has restarted, prior to generating sales and positive cash flow from production, our capital expenditure needs have been and will continue to be substantial.

As of December 31, 2025, we had unrestricted cash and cash equivalents of $97.7 million. Our total debt as of December 31, 2025 was $921.6 million, comprised of principal and paid-in-kind accrued interest on the Senior Secured Term Loan, which matures on the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan, refer to further discussion of the Second Debt Amendment at Note 6 — Debt in the consolidated financial statements).

Capital Raising Activities. Prior to the Business Combination, Flame had approximately $62.2 million in its trust account, which consisted of proceeds from the public stockholders and the private placement investors in connection with the Company’s initial public offering, less redemptions. On the Closing Date, the Company issued 44,024,910 shares of Common Stock of the Company, at a price of $10.00 per share for aggregate gross proceeds of $440.2 million (the “First PIPE Investment”). On September 26, 2024, the Company issued 7,500,000 shares of Common Stock of the Company, at a price of $20.00 per share for aggregate gross proceeds of approximately $150.0 million (“Second PIPE Investment”).

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Additionally, the Company received approximately $183.5 million in gross proceeds from the exercise of 15,957,820 warrants for 15,957,820 shares of Common Stock.

In May 2025, the Company raised an additional $295.0 million in gross proceeds from the sale of 10,000,000 shares of Common Stock in the 2025 Offering. On November 12, 2025, the Company issued 45,454,546 shares of Common Stock of the Company, at a price of $5.50 per share for aggregate gross proceeds of approximately $250.0 million (“Third PIPE Investment”). Further, more than $600 million of the Purchase Price (as defined in the Senior Secured Term Loan) was seller-financed through the Senior Secured Term Loan.

On February 2, 2026, the Company established an “at-the-market” equity offering program pursuant to a sales agreement with TD Securities (USA) LLC and Jefferies LLC (collectively, the “Sales Agents”) under which the Company may offer and sell, at its discretion, shares of its Common Stock from time to time. The aggregate offering size under the program is up to $250.0 million of Common Stock, and any sales completed by the Sales Agents thereunder will be made pursuant to the Company’s effective shelf registration statement on Form S-3 and an accompanying prospectus supplement. The Company expects to use the net proceeds from any sales under the program for general corporate purposes, and restart-related capital expenditures.

Liquidity Requirements and Capital Expenditures. We currently estimate no remaining start-up expenses to recommence oil sales via the Santa Ynez Pipeline System, other than applicable legal expenses. Upon resuming petroleum transportation through the Santa Ynez Pipeline System, we anticipate approximately $100.0 million to $200.0 million in additional post-sales capital expenditures for 2026, primarily related to facilities, pipeline ramp-up activities, and other property, plant and equipment, depending on timing and excluding any OS&T-related capital expenditures. Alternatively, if we elect to pursue the OS&T Strategy, total anticipated 2026 capital expenditures are estimated to be approximately $475.0 million, including costs to acquire and purchase the vessel in addition to incremental investments associated with related infrastructure. Depending on the timing and outcome of regulatory approvals and the execution of commercial arrangements, we could incur capital expenditures beyond these ranges. We cannot provide any assurances that our assumptions used to estimate our liquidity requirements, our anticipated cost savings or reductions, or the costs required to achieve operations under the OS&T Strategy will be correct, as we have not previously undertaken such actions and as a consequence, our ability to predict such amounts is uncertain and may be impacted by factors outside of our control.

After either (i) resumption of oil sales through the Santa Ynez Pipeline System, or (ii) continued receipt of clearance from regulators with respect to the OS&T Strategy, we expect to pursue additional debt financing options, which may include the issuance of public or private debt securities, bank financing or a combination thereof. However, there can be no assurance that we will be able to obtain such additional debt financing on commercially agreeable terms, or at all. After sales of production commences, we expect an increase in operating cash flows that should allow us to fund further capital expenditures. If we are unable to obtain funds or provide funds as needed for the planned capital expenditure program, we may not be able to finance the capital expenditures necessary to restart production sales or sustain production thereafter.

Going Concern

Since the Business Combination the Company has been strictly focused on recommencing oil sales from the SYU Assets, including capital expenditures to repair and maintain the SYU Assets. Much like other pre-revenue companies, the Company has experienced losses from operations and has negative cash flows from operations since inception. We have addressed near-term capital funding needs with proceeds from the First PIPE Investment, the Second PIPE Investment, the exercise of Warrants (refer to Note 7 — Warrants for additional details regarding the warrant exercises), the 2025 Offering, and the Third PIPE Investment. However, our plans for recommencement of sales of production are contingent upon approvals from federal, state and local regulators.

As of December 31, 2025, the Company reported unrestricted cash of $97.7 million, total debt of $921.6 million, and an accumulated deficit of $1.1 billion. On November 20, 2025 the maturity date was successfully extended upon the effectiveness of the Second Debt Amendment to the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan, refer to Note 6 — Debt for additional details regarding the Second Debt Amendment).

If our estimates of the costs to reach first sales via the Santa Ynez Pipeline System or the OS&T are less than the actual amounts necessary to do so, we may have insufficient funds available to operate our business prior to first sales of production and will need to raise additional capital. If we are unable to raise additional capital, we may be required to take additional measures to conserve liquidity, which could include, among other things, reducing overhead expenses.

Due to the uncertainty regarding our resumption of sales of production volumes, and lack of assurance that new financing, or refinancing of the Senior Secured Term Loan, will be available to us on commercially acceptable terms, if at all,

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substantial doubt exists about the Company’s ability to continue as a going concern. The financial statements included in this annual report do not include any adjustments relating to the recovery of the recorded assets or the classification of the liabilities that could be necessary if the Company is unable to continue as a going concern.

Cash Flows

The following table summarizes cash flows from Operating, Investing and Financing activities:

Successor

Predecessor

Change

(dollars in thousands)

Year Ended December 31, 2025

February 14—December 31, 2024

January 1—February 13, 2024

Cash flows (used in) provided by:

Operating activities

Investing activities

Financing activities

Net change in cash and cash equivalents

Cash Flows from Operating Activities. Since petroleum has not been transported through Pipeline Segments 324 and 325, no operating revenues have been recognized for the comparative periods. The net cash used in operating activities for the Company was $351.7 million for the year ended December 31, 2025, representing an increase in cash used in operating activities of $166.3 million, or 90%, compared to net cash used in operating activities of $22.5 million for the period January 1, 2024 through February 13, 2024 (Predecessor) and $163.0 million net cash used in operating activities from February 14, 2024 through December 31, 2024 (Successor), respectively, or a combined $185.4 million. The primary use of cash can be attributed to maintenance and operational readiness activities in the Predecessor and Successor periods, with additional general and administrative costs incurred post the Business Combination in the Successor period.

For the year ended December 31, 2025, we had a net loss of $410.2 million, which consists of a non-cash decrease of $89.2 million in fair value of the warrants, non-cash paid-in-kind interest of $87.7 million, non-cash stock-based compensation of $42.7 million, non-cash tax expense of $11.7 million, and non-cash depreciation, depletion, amortization and accretion of $12.9 million. Changes in Inventory for the period of $6.1 million is attributable to the cash paid for expenses capitalized as Inventory on the consolidated balance sheet as of December 31, 2025 and changes of Prepaid expenses and other assets for the period of $7.5 million is attributable to the cash paid for future period expenses, net of non-cash amortization of such payments. For the period January 1, 2024 through February 13, 2024 (Predecessor), SYU incurred a net loss of $11.8 million and for the period February 14, 2024 through December 31, 2024 (Successor) the Company incurred a net loss of $617.3 million, respectively, or a combined $629.1 million. Our combined net loss was partially offset by a non-cash increase in the fair value of our warrant liabilities of $227.5 million, non-cash stock based compensation of $91.6 million, and non-cash paid-in-kind interest $66.3 million. Changes in accounts payable of $46.0 million is primarily attributable to the Grey Fox Matter settlement, with $35.0 million in accounts payable and accrued liabilities as of December 31, 2024 (Refer to Note 2 — Significant Accounting Policies ). Future cash flow from operations will depend on our ability to recognize sales of production volumes, as well as the prices of oil, natural gas and NGLs.

Cash Flows from Investing Activities. Net cash used in investing activities was $417.6 million for the year ended December 31, 2025, representing an increase in cash used in investing activities of $141.4 million, or 51%, compared to the net cash used investing activities of zero for the period January 1, 2024 through February 13, 2024 (Predecessor) and $276.2 million for the period February 14, 2024 through December 31, 2024 (Successor), or a combined $276.2 million. Investing cash flow for the year ended December 31, 2025 consists of cash paid for capital expenditures associated with restart efforts and for the period February 14, 2024 through December 31, 2024 (Successor) is comprised of $203.9 million paid to EM at Closing per settlement statement and $72.3 million paid for capital expenditures associated with restart efforts. There was no net cash used in investing activities for the Predecessor period since production from the SYU Assets temporarily ceased in 2015 and had no investing activities.

Cash Flows from Financing Activities. Net cash provided by financing activities was $531.2 million for the year ended December 31, 2025, consisting of $545.0 million in aggregate gross proceeds from our 2025 offerings, net of related fees paid of $13.8 million. Net cash provided by financing activities for the period January 1, 2024 through February 13, 2024 (Predecessor) was $22.5 million and net cash provided by financing activities for the period February 14, 2024 through December 31, 2024 (Successor) was $721.7 million, respectively, or a combined $744.1 million.

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Financing activities for the period January 1, 2024 through February 13, 2024 (Predecessor) consists of EM capital contributions financing the maintenance and operational readiness activities. Financing activities for the period February 14, 2024 through December 31, 2024 (Successor) are comprised of $440.2 million of gross proceeds from the First PIPE Investment, $150.0 million of gross proceeds from the Second PIPE Investment, or $590.2 million in aggregate gross private offering proceeds, net of $30.6 million of capitalized transaction expenses, or $559.7 million net, plus $183.5 million net cash received from warrant exercises, less deposit paid to EM for the Term Loan of $18.8 million, payment of debt issuance costs of $1.6 million, and repayment of Flame non-convertible promissory notes — related parties for $1.1 million.

Contractual Obligations

Pursuant to the Senior Secured Term Loan, which financed most of the Purchase Price (as defined in the Senior Secured Term Loan), Sable incurred interest for the period prior to the effectiveness of the Second Debt Amendment of ten percent (10%) per annum, and fifteen percent (15%) per annum subsequent to the Second Debt Amendment, compounded annually (refer to Note 6 — Debt for additional details regarding the Second Debt Amendment). Interest on the Senior Secured Term Loan is payable in arrears on January 1st of each year but, at Sable’s election, accrued but unpaid interest may be deemed paid on each interest payment date by adding the amount of interest owed to the outstanding principal (paid-in-kind) amount. On December 13, 2024, the Company entered into the Fourth Amendment to the Sable-EM Purchase Agreement, pursuant to which the following definitions were amended. “Restart Production” was redefined as 150 days after first production, extending the maturity date of the EM Term Loan by 60 days. “Restart Failure Date” was extended an additional 60 days to March 1, 2026.

On May 15, 2025, the Company restarted production at SYU and as a result, required the Senior Secured Term Loan to be refinanced or otherwise paid in full within 240 days following such first production date, or January 9, 2026. On November 24, 2025 the Second Debt Amendment became effective and extended the maturity date to the earlier of (i) March 31, 2027 or (ii) the date falling 90 days after first sales of Hydrocarbons (as defined in the Senior Secured Term Loan).

Additional obligations include the performance of ARO as referenced under “ Critical Accounting Policies and Estimates—Asset Retirement Obligations ” below.

Off Balance Sheet Arrangements

As of December 31, 2025, the Company had no off-balance sheet arrangements.

Critical Accounting Estimates

The preparation of consolidated financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the combined financial statements, and income and expenses during the periods reported. Actual results could materially differ from those estimates.

Property, Plant and Equipment.

Cost Basis . Oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of resources to justify its completion as a producing well and where sufficient progress assessing the resources and the economic and operating viability of the project is being made. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.

Other Property and Equipment . Other property and equipment primarily consist of onshore midstream facilities, transportation assets and assets related to the Company’s corporate office (the “Office Assets”). Due to the nature of such assets, the onshore midstream facilities are presented within oil and gas properties, while the transportation assets and the Office Assets are presented within other assets on the consolidated balance sheets.

Depreciation, Depletion and Amortization . Depreciation, depletion and amortization are primarily determined under the unit-of-production method, which is based on estimated asset service life taking obsolescence into consideration.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with

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productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed resources of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

The SYU Assets had not produced oil and gas since 2015 due to a pipeline incident but had been maintained by EM to preserve it in an operation-ready state and thus no depletion had been recognized prior to achieving first production on May 15, 2025. Depletion, depreciation and amortization of $6.0 million associated with the SYU Assets was recognized during the year ended December 31, 2025; however, as the associated production remained in the Company’s storage tanks as of December 31, 2025, the entire amount has been capitalized as Inventory on the consolidated balance sheet. The recognition of depletion expense on the consolidated statement of operations will commence upon the commencement of sales of production.

Inventory. Production volumes for the period from May 15, 2025 through December 31, 2025 were retained within the Company’s storage tanks and recognized as short term oil inventory, and the associated depletion expense was capitalized, as noted above. ASC 330 dictates that inventory shall initially be valued at the price paid or consideration given to acquire an asset. By analogy, the Company capitalized the costs incurred that were directly attributable to producing and transporting the production to the onshore storage tanks, including associated depreciation, depletion, and amortization. Inventory is presented as its own line in the consolidated balance sheet.

The Company has oil inventory storage capacity of 540 MBbls onshore at LFC. The Company generally expects the inventory volumes to fluctuate over time to maintain optimal operational efficiencies. The ending volume of inventory that remains in the onshore storage tanks is measured at the current period’s cost, and a lower of cost or net realizable value assessment is performed for each reporting period.

Impairment Assessment. Assets are tested for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:

• a significant decrease in the market price of a long-lived asset;

• a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, including a significant decrease in current and projected resource or reserve volumes;

• a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;

• an accumulation of project costs significantly in excess of the amount originally expected; and

• a current-period operating loss combined with a history and forecast of operating or cash flow losses.

We monitor for indicators of potential impairment throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932. Asset valuation analysis, profitability reviews and other periodic control processes assist in assessing whether events or changes in circumstances indicate the carrying amounts of any of the assets may not be recoverable.

If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, management estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on assumptions which are developed by management and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, and development and operating costs. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities.

An asset group is impaired if its estimated undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. The assessment of fair value is

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based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, drilling and development costs, operating costs and discount rates which are reflective of the characteristics of the asset group.

Asset Retirement Obligations . The Company’s ARO primarily relate to the future plugging and abandonment of oil and gas properties and related facilities. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Company uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates.

Derivative Warrant Liabilities. We do not use derivative instruments to hedge exposures to cash flow, market, or foreign currency risks. We evaluate all of our financial instruments, including issued stock purchase warrants, to determine if such instruments are derivatives or contain features that qualify as embedded derivatives, pursuant to ASC 480 and ASC 815-15. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period.

All of our outstanding warrants are recognized as derivative liabilities in accordance with ASC 815-40. Accordingly, we recognize the warrant instruments as liabilities at fair value and adjust the instruments to fair value at each reporting period. The liabilities are subject to re-measurement at each balance sheet date until exercised, and any change in fair value is recognized in our statement of operations. The private placement warrants and the working capital warrants are measured at fair value using the Modified Black-Scholes Optional Pricing Model.

Recent Accounting Pronouncements

In November 2024, the FASB issued ASU 2024-03, Income Statement — Reporting Comprehensive Income — Expense Disaggregation Disclosures (Subtopic 220-40) — “Disaggregation of Income Statement Expenses.” The FASB issued this ASU to improve the disclosures about a public business entity’s expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization, and depletion) in commonly presented expenses captions (such as cost of sales, SG&A, and research and development). The amendments in this ASU are effective for annual periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently reviewing what impact, if any, adoption will have on its disclosures.

Our management does not believe that any other recently issued, but not yet effective, accounting standards if currently adopted would have a material effect on our financial statements.