Blue Dolphin Energy Co: Form 10-K for the period ended Dec 31, 2023

The following section of this Annual Report on Form 10-K generally refers to business developments during the twelve months ended December 31, 2023. Discussion of, or references to, prior period business developments that are not included in this Form 10-K can be found in “Part I, Item 1. Business” of our Annual Report on Form 10-K for the year ended December 31, 2022.

Company Overview

Blue Dolphin was formed in 1986 as a Delaware corporation. The company is an independent downstream energy company operating in the Gulf Coast region of the U.S. Operations primarily consist of a light sweet-crude, 15,000-bpd crude distillation tower, and approximately 1.25 million bbls of petroleum storage tank capacity in Nixon, Texas. Blue Dolphin trades on the OTCQX under the ticker symbol “BDCO.”

Assets are organized into two business segments: ‘refinery operations’ (owned by LE) and ‘tolling and terminaling services’ (owned by LRM and NPS). ‘Corporate and other’ includes Blue Dolphin subsidiaries BDPL (inactive pipeline and facilities assets), BDPC (inactive leasehold interests in oil and gas wells), and BDSC (administrative services). For more information related to our business segments, see “Part I. Item 1. Business—Refinery Operations, —Tolling and Terminaling Operations, and — Inactive Operations” and “Part I. Item 2. Properties” in this report.

Unless the context otherwise requires, references in this report to “we,” “us,” “our,” or “ours” refer to Blue Dolphin, one or more of its consolidated subsidiaries, or all of them taken as a whole.

Jonathan Carroll, our Chief Executive Officer, and an Affiliate together controlled 83% of the voting power of our Common Stock as of the filing date of this report. An Affiliate also operates and manages all Blue Dolphin properties, funds working capital requirements during periods of working capital deficits, guarantees certain of our third-party secured debt, and is a significant customer of our refined products. Blue Dolphin and certain subsidiaries are currently parties to various agreements with Affiliates. See “Part I, Item 1A. Risk Factors” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (3)” for additional disclosures related to Affiliate agreements, arrangements, and risks associated with working capital deficits.

Going Concern Assessment

Certain conditions and events were noted that initially caused management to evaluate our ability to continue as a going concern. These conditions and events include significant debt either in default or under a forbearance agreement that expired on March 29, 2024 and classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 2023 and current and historical working capital deficits at December 31, 2023. Our current assets totaled $49.3 million, and our current liabilities, excluding the current portion of long-term debt, totaled $16.0 million as of December 31, 2023. Management believes that we have sufficient liquidity to meet our obligations as they become due through the generation of cash flows from operations and liquidation of current working capital amounts for a reasonable period (defined as one year from the issuance of these financial statements). To bolster working capital reserves, management continues efforts to restructure debt obligations and reduce cash requirements. Management acknowledges that uncertainty remains related to future operating margins. However, management has a reasonable expectation of Blue Dolphin's ability to generate adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on our long-term debt. Our audited consolidated financial statements have been prepared assuming we will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business.

Our significant current debt resulted from certain third-party loan agreements being classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2023 and 2022. Excluding accrued interest, we had current debt of $39.4 million and $47.4 million as of December 31, 2023 and 2022, respectively. Our significant current debt at December 31, 2023 consisted of bank debt to Veritex and GNCU.

Forbearance Agreements and Default

Kissick Forbearance Agreement. Pursuant to the Kissick Forbearance Agreement, Kissick Noteholder agreed to forbear from exercising any of its rights and remedies related to existing defaults pertaining to payment violations under the Kissick Debt. Under the terms of the Kissick Forbearance Agreement, LE agreed to make monthly principal and interest payments totaling $0.5 million beginning in April 2023, continuing on the first of each month through February 2025, with a final payment of $0.4 million to Kissick Noteholder on March 1, 2025. LE paid Kissick Noteholder $4.5 million for the twelve months ended December 31, 2023. As of the filing date of this report, the Kissick Debt was in forbearance related to past defaults prior to April 2023.

LEH Forbearance Agreement. Pursuant to the LEH Forbearance Agreement, LEH agreed to forbear from exercising any of its rights and remedies related to existing defaults pertaining to payment violations under the BDPL-LEH Loan Agreement. Under the terms of the LEH Forbearance Agreement, BDPL agreed to make interest-only monthly payments approximating $0.05 million beginning in May 2023, continuing on the fifteenth of each month through April 2025. Beginning in May 2025, BDPL agreed to make principal and interest monthly payments approximating $0.4 million through April 2027. Interest will be incurred throughout the agreement, including the interest-only payment period. BDPL paid LEH approximately $3.4 millionfor the twelve months ended December 31, 2023. As of the filing date of this report, the BDPL-LEH Loan Agreement was in forbearance related to past defaults prior to May 2023.

Defaults. As of December 31, 2023 and the filing date of this report, we were in default under the NPS Term Loan Due 2031 due to covenant violations. At December 31, 2023 and through March 29, 2024, we were in forbearance under the LE Term Loan Due 2034 and LRM Term Loan Due 2034. As of the filing date of this report, we were in default under the LE Term Loan Due 2034 and LRM Term Loan Due 2034 due to covenant violations. Defaults may permit lenders to declare the amounts owed under the related loan agreements immediately due and payable, exercise their rights with respect to collateral securing obligors’ obligations, and/or exercise any other rights and remedies available.

Refining Margins

Our results of operations and liquidity are highly dependent upon the margins we receive for our refined products. The dollar per bbl commodity price difference between crude oil and condensate (input) and refined products (output) is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. The general outlook for the oil and natural gas industry for 2024 remains unclear given uncertainties surrounding general macroeconomic conditions related to inflation, interest rates, and capital and credit markets, geopolitical tensions, including military conflicts in Ukraine and Israel and escalations in the Middle East, and COVID-19.

Operating Risks

Successful execution of our business strategy depends on several critical factors, including having adequate working capital, favorable refining margins, and maintaining operation of the Nixon refinery.

• Working Capital – We have historically had working capital deficits primarily due to having significant current debt. Having sufficient working capital is necessary to meet contractual, operational, regulatory, and safety needs. Our short-term working capital needs are primarily related to: (i) purchasing crude oil and condensate to operate the Nixon refinery, (ii) reimbursing LEH for direct operating expenses and paying the LEH operating fee under the Third Amended and Restated Operating Agreement, (iii) servicing debt, (iv) maintaining and improving the Nixon facility through capital expenditures, and (v) meeting regulatory compliance requirements. Our long-term working capital needs are primarily related to repayment of long-term debt obligations. To avoid business disruptions and manage cash flow, we optimize receivables and payables by prioritizing payments, optimize inventory levels based on demand, monitor discretionary spending, and carefully manage capital expenditures.
• Refining Margins – Refining margins, which are affected by commodity prices and refined product demand, are volatile, and a reduction in refining margins will adversely affect the amount of cash we will have available for working capital. Crude oil refining is primarily a margin-based business. To improve margins, we must maximize yields of higher value finished petroleum products and minimize costs of feedstocks and operating expenses. When the spread between these commodity prices decreases, our margins are negatively affected. Although an increase or decrease in the commodity price for crude oil and other feedstocks generally results in a similar increase or decrease in commodity prices for finished petroleum products, typically there is a time lag between the two. The effect of crude oil commodity price changes on our finished petroleum product commodity prices therefore depends, in part, on how quickly and how fully the market adjusts to reflect these changes. Unfavorable margins may have a material adverse effect on our earnings, cash flows, and liquidity. To remain competitive in a volatile commodity price environment, we adjust throughput and production based on market conditions and adjust our product slate based on commodities pricing.
• Nixon Refinery Operation – We maintain relationships with suppliers that source and repair key components of the Nixon refinery. We expect our suppliers to maintain an adequate supply of component products and, when components are sent out for repair, to timely deliver components. However, in some cases, increases in demand or supply chain disruptions have led to part and component constraints. We use several suppliers and monitor supplier financial viability to mitigate supply-based risks that could cause a business disruption.

Uncertainties remain surrounding general macroeconomic conditions related to inflation, interest rates, and capital and credit markets, geopolitical tensions, including military conflicts in Ukraine and Israel and escalations in the Middle East, COVID-19, and the extent to which these factors may impact working capital, commodity prices, refined product demand, our supply chain, financial condition, liquidity, results of operations, and future prospects will depend on future developments, which cannot be predicted with any degree of confidence. We can provide no guarantees that: our business strategy will be successful, Affiliates will continue to fund our working capital needs when we experience working capital deficits, we will meet regulatory requirements to provide additional financial assurance (supplemental pipeline bonds) and decommission offshore pipelines and platform assets, we can obtain additional financing on commercially reasonable terms or at all, or margins on our refined products will be favorable. Further, if third parties exercise their rights and remedies under secured loan agreements that are in default, our business, financial condition, and results of operations will be materially adversely affected.

Downstream Operations

The refinery operations business segment consists of the following assets and operations:

Crude Oil and Condensate Supply. Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. During 2022 and 2023, we operated under a crude supply agreement with Tartan. Related to the Tartan Crude Supply Agreement, Tartan stored crude oil at the Nixon facility under a terminal services agreement. In a letter dated October 31, 2023, Tartan provided LE and NPS the required 60 days’ notice of its intention to terminate the Tartan Crude Supply Agreement and terminal services agreement. The effective date of the termination was December 31, 2023. On December 29, 2023, we entered a new crude supply agreement with MVP, effective January 1, 2024. This agreement provides a firm source of light-sweet Eagle Ford crude oil to the Nixon facility under improved credit terms, and management believes that MVP can provide us with adequate amounts of crude oil and condensate for the foreseeable future. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (5)” to our consolidated financial statements for additional information regarding the crude supply agreement with MVP.

Under the volume-based Tartan Crude Supply Agreement, Tartan was to deliver 24.8 million net bbls of crude oil. For the twelve months ended December 31, 2023 and 2022, volume delivered under the Tartan Crude Supply Agreement, as a percentage of the total net bbls of crude oil deliverable, was 71.0% and 54.8%, respectively. During the twelve months ended December 31, 2023, substantially all our crude was sourced from Tartan. During the twelve months ended December 31, 2022, all our crude oil was sourced from Tartan.

Our financial health has been materially and adversely affected by significant current debt, certain of which is in default, historical net losses, working capital deficits, and margin volatility. If we are required to obtain our crude oil and condensate without the benefit of a long-term crude supply agreement, our exposure to the risks associated with volatile crude oil prices may increase, crude oil transportation costs could increase, and our liquidity may be reduced. Similarly, if producers experience crude supply constraints and increased transportation costs, our crude acquisition costs may rise, or we may not receive sufficient amounts to meet our needs, which could result in refinery downtime and could materially affect our business, financial condition, and results of operations.

Products and Markets. Our market is the Gulf Coast region of the U.S., which is represented by the EIA as PADD 3. We sell our products primarily in the U.S. within PADD 3. Occasionally, we sell refined products to customers that export to other countries, such as low sulfur diesel to Mexico.

The Nixon refinery’s product slate is adjusted based on market demand. We currently produce a single finished product – jet fuel – and several intermediate products, including naphtha, HOBM, and AGO. Our jet fuel is sold to an Affiliate, which is HUBZone certified. The product sales agreement with the Affiliate automatically renews for one-year periods unless sooner terminated between the parties. Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing.

Customers. Customers for our refined products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston – San Antonio – Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers, including month-to-month, six months, and up to one-year terms. Certain of our contracts require our customers to prepay and us to sell fixed quantities and/or minimum quantities of finished and intermediate petroleum products. Many of these arrangements are subject to periodic renegotiation on a forward-looking basis, which could result in higher or lower relative prices on future sales of our refined products.

Competition. Many of our competitors are substantially larger than us and are engaged on a national or international level in many segments of the oil and gas industry, including exploration and production, gathering and transportation, and marketing. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these business segments. We compete primarily based on cost. Due to the low complexity of our simple “topping unit” refinery, we can be nimble in adjusting our refined products slate because of changing commodity prices, market demand, and refinery operating costs.

Safety and Downtime. We operate the refinery in a manner that is materially consistent with industry safety practices and standards. EPA, OSHA, and comparable state and local regulatory agencies provide oversight for personnel safety, process safety management, and risk management to prevent or minimize the accidental release of toxic, reactive, flammable, or explosive chemicals. Most of our storage tanks are equipped with leak detection devices. We also have response and control plans in place for spill prevention and emergencies.

The Nixon refinery periodically undergoes planned and unplanned temporary shutdowns. We typically complete a planned turnaround annually to repair, restore, refurbish, or replace refinery equipment. However, the timing of planned turnarounds is adjusted to capitalize on favorable market conditions. Occasionally, unplanned shutdowns occur. Unplanned downtime can occur for a variety of reasons; however, common reasons for unplanned downtime include repair/replacement of disabled equipment, crude deficiencies associated with cash constraints, high temperatures, and power outages. The Nixon facility improved uptime by 10 days in the twelve months ended December 31, 2023, experiencing 12 days of downtime for compared to 22 days of downtime in the twelve months ended December 31, 2022. Refinery downtime in 2023 related to maintenance and repairs (9 days) and a planned turnaround (3 days); downtime in 2022 related to maintenance and repairs (13 days), weather (5 days), and crude deficiencies associated with cash constraints (4 days). Throughout 2023 management focused on identifying safety and mechanical process improvements to optimize plant operations, particularly given increasing extreme weather impacts.

We are particularly vulnerable to operation disruptions because all our refining operations occur at a single facility. Any scheduled or unscheduled downtime results in lost margin opportunity, reduced refined products inventory, and potential increased maintenance expense, all of which could reduce our ability to meet our payment obligations.

Midstream Operations

Our tolling and terminaling segment consists of the following assets and operations:

Products and Customers. The Nixon facility’s petroleum storage tanks and infrastructure are primarily suited for crude oil and condensate and refined products, such as naphtha, jet fuel, diesel, and fuel oil. Storage customers are typically refiners in the lower portion of the Texas Triangle (the Houston – San Antonio – Dallas/Fort Worth area). Shipments are received and redelivered from within the Nixon facility via pipeline or from third parties via truck. Contract terms range from month-to-month to three years.

Operations Safety. Our midstream operations are operated in a manner materially consistent with industry safe practices and standards. These operations are subject to OSHA regulations and comparable state and local regulators. Storage tanks used for terminal operations are designed for crude oil and condensate and refined products, and most are equipped with appropriate controls that minimize emissions and promote safety. Our terminal operations have response and control plans, spill prevention and other programs to respond to emergencies.

Inactive Operations

We own other pipeline and facilities assets and have leasehold interests in oil and gas properties. These assets are inactive. We account for these inactive operations in ‘corporate and other.’ Our pipeline assets have been fully impaired since 2016 and our oil and gas leasehold interests have been fully impaired since 2011. Our pipeline assets and oil and gas leasehold interests had no revenue during the twelve months ended December 31, 2023 and 2022.

Blue Dolphin Energy Company

Pipeline and Facilities Safety.

Although our pipeline and facility assets are inactive, they require upkeep and maintenance and are subject to safety regulations under OSHA, PHMSA, BOEM, BSEE, and comparable state and local regulators. We have response and control plans, spill prevention and other programs to respond to emergencies related to these assets.

Insurance and Risk Management

Our operations are subject to significant hazards and risks inherent in crude oil and condensate refining operations, as well as the transportation and storage of crude oil and condensate and refined products. We have property damage, business interruption, and pollution liability coverages at the Nixon facility. Business interruption coverage is for 24 months from the date of the loss, subject to a deductible with a 45-day waiting period. Pollution liability provides coverage due to named perils for claims involving pollutants where the discharge is sudden, accidental, and first commences at a specific day and time during the policy period. The pollution policy is subject to a retention and deductible and contains discovery requirements, reporting requirements, exclusions, definitions, conditions, and limitations that could apply to a particular pollution claim. As a result, there can be no assurance such claim will be adequately insured for all potential damages.

Additional coverage includes umbrella, excess liability, workers’ compensation, directors’ and officers’ liability, environmental liability, and other business risks. These coverages are supported by safety and other risk management programs. Our insurance program may not cover all operational risks and costs and may not provide sufficient coverage in the event of a claim. We do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Losses in excess of our insurance coverage or cancellation of policies could have a material adverse effect on our business, financial condition, and results of operations.

Intellectual Property

We rely on intellectual property laws to protect our brand, as well as those of our subsidiaries. “Blue Dolphin Energy Company” is a registered trademark in the U.S. in name and logo form. “Petroport, Inc.” is a registered trademark in the U.S. in name form. In addition, “www.blue-dolphin-energy.com” (http://www.blue-dolphin-energy.com”) is a registered domain name.

Human Capital Management

General. Our operations and activities are managed by an Affiliate. We do not have any employees. As of December 31, 2023,129 employees of the Affiliate provided support for our operations pursuant to the Third Amended and Restated Operating Agreement. None of these employees were covered by collective bargaining agreements. Under the Third Amended and Restated Operating Agreement, the Affiliate operates and manages all of our properties.

We believe that our personnel provide a competitive advantage for our success. We seek to foster a culture that supports diversity and inclusion, and we strive to provide a safe, healthy, and rewarding work environment for our personnel.

Safety, Health, and Wellness. We must comply with a number of federal and state laws and regulations related to safety that protect the health and safety of our workforce. We operate a safety and health program with participation by personnel at all levels of the organization. In 2022, we implemented eCompliance, a mobile software solution that increases frontline adoption of health and safety policies and reduces on-site risks. Despite our efforts to achieve excellence in our safety and health performance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities.

Inclusion and Diversity. We continue to evaluate measures to put in place and track our progress with regard to diversity and inclusion. As of December 31, 2023, employees of the Affiliate self-identified as37% White, 39% Hispanic Latino, 17% Black or African American, 2% Asian, and 4% two or more races.

Government Regulations

General. Our operations are subject to extensive and frequently changing federal, state, and local laws, regulations, permits, and ordinances relating to the protection of the environment. Among other things, these laws and regulations govern obtaining and maintaining construction and operating permits, the emission and discharge of pollutants into or onto the land, air, and water, the handling and disposal of solid, liquid, and hazardous wastes and the remediation of contamination. Compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate, and upgrade equipment and facilities. Failing to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. These requirements may also significantly affect our customers’ operations and may have an indirect effect on our business, financial condition, and results of operations. However, we do not expect such effects will have a material impact on our financial position, results of operations, or liquidity.

Air Emissions and Climate Change Regulations. Our operations are subject to the CAA and comparable state and local statutes. Under these laws, we are required to obtain permits, as well as test, monitor, report, and implement control requirements. If regulations become more stringent, additional emission control technologies may be required to be installed at the Nixon facility and certain emission sources located offshore, and our ability to secure future permits may become less certain. Any such future obligations could require us to incur significant additional capital or operating costs.

The EPA has undertaken significant regulatory initiatives, including the Petroleum Refinery National Initiative, under authority of the CAA’s NSR/PSD program to further reduce emissions of volatile organic compounds, nitrogen oxides, sulfur dioxide, and particulate matter. These regulatory initiatives have targeted industries with large manufacturing facilities that are significant sources of emissions, such as refining, paper and pulp, and electric power generating industries. The basic premise of these initiatives is the EPA’s assertion that many of these industrial establishments have modified or expanded their operations over time without complying with NSR/PSD regulations, which result in emission increases above threshold limits. As part of these regulatory initiatives, the EPA obtained consent decrees with several refiners that require refiners to make significant capital expenditures to install emissions control equipment at selected facilities. We are not under a consent decree, and as a small refiner, we do not expect any additional requirements to have a material impact on our financial position, results of operations, or liquidity.

In February 2024, the EPA released a final rule to lower the annual health-based NAAQS for fine particulate matter to 9 micrograms per cubic liter from the current level of 12 micrograms per cubic liter. To implement the revised fine particulate matter NAAQS, all states will need to review their existing air quality management infrastructure State Implementation Plan for fine particulate matter and ensure it is appropriate and adequate. Where areas remain in non-attainment or come into non-attainment as a result of the revised NAAQS, additional planning and emissions control obligations may be required. The ongoing and potential future requirements imposed by states to meet the fine particulate matter NAAQS could have direct impacts on terminaling facilities through additional requirements and increased permitting costs and could have indirect impacts through changing or decreasing fuel demand.

Pursuant to the Energy Policy Act of 2005 and Energy Independence and Security Act of 2007, the EPA promulgated RFS and RFS2, respectively, which requires obligated parties, defined by the EPA as refiners or importers of transportation fuels, to either blend “renewable fuels,” such as ethanol and biofuels, into their transportation fuels or purchase renewable fuel credits, known as renewable identification numbers, in lieu of blending. The EPA granted the Nixon refinery a small refinery exemption from RFS2 requirements for 2013 and 2014. In 2014, the Nixon refinery began producing HOBM, a non-transportation lubricant blend product. After 2014, refined products in our product slate no longer fall under RFS or RFS2 requirements.

Currently, multiple legislative and regulatory measures to address greenhouse gas emissions are in various phases of discussion or implementation. These include actions to develop national, state, or regional programs, each of which would require reductions in our greenhouse gas emissions or those of our customers. In 2015, the EPA amended the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program, to include among other things a new Onshore Petroleum and Natural Gas Gathering and Boosting segment that encompasses greenhouse gas emissions from equipment and sources within the petroleum and natural gas gathering boosting systems. In 2016, the EPA promulgated regulations regarding performance standards for methane emissions from new and modified oil and gas production and natural gas processing and transmission facilities, and in September 2018, proposed targeted improvements to these standards to streamline implementation of the rules. In August 2022, Congress passed and President Biden signed into law the Inflation Reduction Act of 2022, which includes nearly $370 billion in climate-related provisions that provide funding, programs, and incentives to accelerate the U.S.'s transition to a clean energy economy. The Inflation Reduction Act of 2022 also imposes a tax, or "methane fee," on energy producers that exceed a certain level of methane emissions. On January 26, 2024, the EPA published a proposed rule to implement the methane fee. These and other legislative regulatory measures will impose additional burdens on our business and those of our customers, and the impact of future GHG regulations on our operations and financial condition is unknown.

Hazardous Substances and Waste Regulations. The CERCLA imposes strict, joint and several liability on a broad group of potentially responsible parties for response actions necessary to address a release of hazardous substances into the environment. The law authorizes two kinds of response actions: (i) short-term removals, where actions may be taken to address releases or threatened releases requiring prompt response, and (ii) long-term remedial response actions, that permanently and significantly reduce the dangers associated with releases or threats of releases of hazardous substances that are serious, but not immediately life threatening. Neither we nor any of our predecessors have been designated as a potentially responsible party under CERCLA or a similar state statute.

We are subject to RCRA requirements for the generation, transportation, treatment, storage, and disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being disposed of on-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes. We generate petroleum product wastes, solid wastes, and ordinary industrial wastes, such as from paints and solvents, that are regulated under RCRA and comparable state statues.

Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal practices. We currently own properties where crude oil, refined petroleum hydrocarbons, and fuel additives have been handled for many years by previous owners. At some sites, hydrocarbons or other waste may have been disposed of or released on or under the properties owned by us or on or under other locations where these wastes have been taken for disposal. Although prior owners and operators may have used operating and waste disposal practices that were standard in the industry at the time, these properties and wastes disposed thereon are now subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed or released wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including impacted groundwater), or to perform remedial operations to prevent future contamination to the extent we are not indemnified for such matters.

Additionally, regulation of PFAS has significantly increased in recent years, at both the federal and state levels. PFAS has been used in oil and gas-related operations, notably in emergency response activities, including in aqueous film forming foam as a vapor and fire suppressant. In January 2024, the EPA announced two waste-related proposed rulemakings. The first proposed rule would list nine (9) PFAS as "hazardous constituents" under RCRA; listing a substance as a hazardous constituent is a preliminary step toward classifying a substance as hazardous waste. The second proposed rule would amend the definition of "hazardous waste" to clarify that the RCRA corrective action authority may be utilized to address emerging contaminants, including PFAS. Moreover, an increasing number of states have sought to regulate PFAS, creating a patchwork of PFAS standards throughout the U.S. We cannot currently predict the impact of PFAS-related regulations on our compliance or remediation costs.

Water Pollution Regulations. Our operations can result in the discharge of pollutants, including chemical components of crude oil and refined products, into federal and state waters. The CWA prohibits the discharge of pollutants into U.S. waters except as authorized by the terms of a permit issued by the EPA or a state agency with delegated authority. The transportation and storage of crude oil and refined products over and adjacent to water involves risks and subjects us to the provisions of the CWA, OPA 90, and related state requirements. Uncertainty has persisted in the federal government's applicable jurisdictional reach under the CWA, and in particular what constitutes a regulated "water of the U.S." ("WOTUS"). The EPA and the USACOE under the Obama, Trump, and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. Most recently, in response to the U.S. Supreme Court's May 2023 ruling in Sackett v. EPA ("Sackett"), the EPA and the USACOE issued a final WOTUS rule that became effective September 8, 2023. In accordance with the U.S. Supreme Court's directive in Sackett, the final rule significantly narrowed the jurisdictional reach of the CWA, but also left unaddressed a number of questions and interpretational uncertainties. Multiple lawsuits challenging the final WOTUS rule remain ongoing, and implementation of the rule is enjoined in about half the states and for certain parties. Continued challenges over the jurisdictional reach of the CWA could result in permitting delays and uncertainty as to compliance requirements.

Spill prevention, control, and countermeasure requirements mandate the use of structures, such as berms and other secondary containment, to prevent hydrocarbons or other pollutants from reaching a jurisdictional body of water in the event of a spill or leak. These requirements prevent pollutant releases and minimize potential impacts should a release occur. We have federally certified OSROs available to respond to a spill and, in the case of our offshore pipelines, we maintain the statutory $35.0 million coverage required proof of financial responsibility. In the event of an oil spill into navigable waters, we can be subject to strict, joint, and potentially unlimited liability for removal costs and other consequences.

Wastewater is subject to restrictions and strict controls under the CWA. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits. Process wastewater from the Nixon refinery is tested and discharged to a nearby municipal treatment facility pursuant to applicable process wastewater permits. Wastewater from our offshore facilities, including our oil and natural gas pipelines and anchor platform, is tested and discharged pursuant to applicable produced water permits. Stormwater at the Nixon facility is tested and discharged pursuant to applicable stormwater permits.

The EPA established an Action Plan for PFAS in 2021. In furtherance of this plan, the EPA proposed national drinking water standards for six (6) PFAS in March 2023. The EPA is expected to issue a final rule in 2024. A number of states have also issued their own drinking water, surface water, and/or groundwater limits for various PFAS. We cannot currently predict the impact of PFAS-related regulations on our compliance or remediation costs.

Offshore Decommission Requirements .

In April 2023, BSEE updated its guidance and regulations on decommissioning that mandates lessees and rights-of-way holders permanently abandon and/or remove platforms and other structures when no longer useful for operations. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the minimum bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM. In June 2023, BOEM issued a proposed rule that would significantly strengthen the financial assurance and bonding requirements for the offshore oil and gas industry.

We are required by BOEM to: (i) maintain acceptable financial assurance (pipeline bonds) for the decommissioning of our assets offshore in federal waters and (ii) decommission these assets following a certain period of inactivity. At December 31, 2023 and 2022, we maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM. At December 31, 2023 and 2022, BDPL maintained $4.5 million and $3.7 million, respectively, in AROs related to decommissioning these assets. See “Part I, Item 1A. Risk Factors” for additional disclosures related to decommissioning obligations for our pipelines and facilities assets and related risks.

OSHA. We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and the public.

Website Access to Reports and Other Information

We make certain filings with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, which are available free of charge through the SEC’s website (http://www.sec.gov) or through our website (http://www.blue-dolphin-energy.com), as soon as reasonably practicable after they are filed with the SEC. We have also posted our Code of Business Ethics, board committee charters and other corporate governance documents on our website. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this report.

You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.

A. Risks Related to Our Business and Industry

A1. Our significant current debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

As described elsewhere in this report, our significant current debt resulted from certain third-party loan agreements being classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2023 and 2022 due to being in default/forbearance. Excluding accrued interest, we had current debt of $39.4 million and $47.4 million as of December 31, 2023 and 2022, respectively. Our significant current debt at December 31, 2023 consisted of bank debt to Veritex and GNCU.

Blue Dolphin, as parent company, has guaranteed the indebtedness of certain subsidiaries. In addition, Affiliates have guaranteed the indebtedness of Blue Dolphin and certain of its subsidiaries. This level of debt in current liabilities and the cross guarantee agreements could have important consequences, such as: (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, potential growth, or for other purposes; (ii) increasing the cost of future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service our debt is dependent upon, among other things, business conditions, our financial and operating performance, our ability to raise capital, and regulatory and other factors, many of which are beyond our control. If our working capital is not sufficient to service our debt, and any future indebtedness that we incur, our business, financial condition, and results of operations will be materially adversely affected. In such a case, we may consider other options, including selling assets, raising additional debt or equity capital, cutting costs, reducing cash requirements, restructuring debt obligations, filing for bankruptcy, or ceasing operating.

A2. Our continued inability to meet financial covenants under certain of our secured loan agreements could adversely impact our ability to obtain new debt, refinance, or restructure existing debt.

As described elsewhere in this report, certain of our secured loan agreements with third parties require us to meet financial covenants. Financial covenants applicable to our secured loan agreements with Veritex and GNCU require us to maintain covenants related to debt to tangible net worth, current assets to current liabilities, debt service coverage, and current ratio. At December 31, 2023 and through March 29, 2024, Veritex agreed to forbear from testing LE and LRM’s compliance with financial covenants under theVeritex Second Amended Forbearance Agreement. However, the LE Term Loan Due 2034 and LRM Term Loan Due 2034 were in default as of the filing date of this report due to covenant violations. Defaults permit lenders to declare the amounts owed immediately due and payable, exercise their rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available.

Our ability to meet financial covenants depends on numerous factors, including sustained positive operating margins and adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on our long-term debt. including our ability to generate sufficient cash flow from operations to service debt obligations or refinance or restructure debt. This depends on, among other things, business conditions, our financial performance, and the general condition of the financial markets. Given uncertainties surrounding general macroeconomic conditions related to inflation, interest rates, and capital and credit markets, geopolitical tensions, including military conflicts in Ukraine and Israel and escalations in the Middle East, COVID-19, and the extent to which these factors may impact working capital, commodity prices, refined product demand, and our supply chain, uncertainties exist related to whether we can successfully generate sufficient cash from operations to repay our outstanding debt or otherwise restructure or refinance the debt. We could be forced to undertake alternate financings, including a sale of additional common stock, negotiate for an extension of the maturity, or sell assets and delay capital expenditures in order to generate proceeds that could be used to repay such indebtedness. We can provide no assurance that we will be able to consummate any such transaction on terms that are commercially reasonable, on terms acceptable to us or at all. If new debt or other liabilities are added to our current consolidated debt levels, the related risks that it now faces could intensify. If new debt or other liabilities are added to LE, LRM, or NPS’ current debt levels, their inability to meet financial covenants could intensify.

A3. Restrictive covenants in our debt instruments may limit our ability to undertake certain types of transactions, which could adversely affect our business, financial condition, results of operations, and our ability to service our indebtedness.

Various covenants in our debt instruments restrict our financial flexibility in a number of ways. Our current indebtedness subjects us to significant financial and other restrictive covenants, including restrictions on our ability to incur additional indebtedness, place liens upon assets, pay dividends or make certain other restricted payments and investments, consummate certain asset sales or asset swaps, conduct businesses other than our current businesses, or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Some of our debt instruments also require us to satisfy or maintain certain financial condition tests in certain circumstances. Our ability to meet these financial condition tests can be affected by events beyond our control and we may not meet such tests. In addition, failing to comply with the provisions of our existing debt could result in a further event of default that could enable our lenders, subject to the terms and conditions of such debt, to declare the outstanding principal, together with accrued interest, to be immediately due and payable. Events beyond our control, including the impact of the COVID-19 pandemic and related governmental responses, volatility in commodity prices, and extreme weather resulting from climate change may affect our ability to comply with our covenants. If we are unable to repay the accelerated amounts, our lenders could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, defaults under our other debt instruments, if any, may be triggered, and our assets may be insufficient to repay such debt in full. In addition, loans provided or guaranteed by the U.S. government, including pursuant to the CARES Act, subject us to additional restrictions on our operations, including limitations on personnel headcount and compensation reductions and other cost reduction activities that could adversely affect us.

A4. Our business, financial condition, and operating results may be adversely affected by increased costs of capital or a reduction in the availability of credit.

Adverse changes to the availability, terms, cost of capital, interest rates, or our credit ratings (which would have a corresponding impact on the credit ratings of our subsidiaries that are party to any cross-guarantee agreements) could cause our cost of doing business to increase by limiting our access to capital, including our ability to refinance maturing or accelerated existing indebtedness on similar terms. In addition, increased crude acquisition costs could adversely impact our working capital. As a result, we cannot provide any assurance that any financing will be available to us in the future on acceptable terms or at all. Any such financing could be dilutive to our existing stockholders. If we cannot raise required funds on acceptable terms, we may further reduce our expenses and we may not be able to, among other things, (i) maintain our general and administrative expenses at current levels; (ii) successfully implement our business strategy; (iii) fund certain obligations as they become due; (iv) respond to competitive pressures or unanticipated capital requirements; (v) repay our indebtedness, or (vi) purchase crude oil to operate the Nixon facility.

A5. Public health crises such as the COVID-19 pandemic have had, and may continue to have, adverse impacts on our business, financial condition, results of operations, and liquidity.

The economic effects from public health crises such as the COVID-19 pandemic on our business were and may again be significant. Although there has been a recovery since the onset of the pandemic in March 2020, there continues to be uncertainty and unpredictability about the lingering impacts to the worldwide economy that could negatively affect our business, financial condition, results of operations, and liquidity in future periods. The extent to which the pandemic and its ongoing effects may adversely impact our future business, financial, and operating results, and for what duration and magnitude, depends on factors that are continuing to evolve, are difficult to predict and, in many instances, are beyond our control. The ultimate outcome of these and other factors may result in many adverse consequences including, but not limited to, disruption or delays to supply chains for critical equipment or feedstock, inflation, increased interest rates, and increased administrative, compliance, and operational costs. In addition, future public health crises could also result in significant economic disruption and other effects that adversely impact our business, financial condition, results of operations, and liquidity in future periods in ways similar to the COVID-19 pandemic. The adverse impacts of the COVID-19 pandemic had, and may continue to have, the effect of precipitating or heightening many of the other risks described in this section.

A6. Affiliates hold a significant ownership interest in us and exert significant influence over us, and their interests may conflict with the interests of our other stockholders; and affiliate transactions may cause conflicts of interest that may adversely affect us.

We have an indirect controlling stockholder. As a related party of an Affiliate, Jonathan Carroll indirectly owned 83% of the voting power of our Common Stock as of the filing date of this report, and by virtue of such stock ownership, Mr. Carroll can control or exert substantial influence over us, including:

• Election and appointment of directors.
• Business strategy and policies.
• Mergers and other business combinations.
• Acquisition or disposition of assets.
• Future issuances of Common Stock or other securities.
• Incurrence of debt or obtaining other sources of financing.

The existence of a controlling stockholder may have the effect of making it difficult for, or may discourage or delay, a third party from seeking to acquire a majority of our outstanding Common Stock, which may adversely affect the market price of our Common Stock.

Affiliate interest may not always be consistent with our interests or with the interests of our other stockholders. Affiliates may also pursue acquisitions or business opportunities in industries in which we compete, and there is no requirement that any additional business opportunities be presented to us. We also have and may in the future enter transactions to purchase goods or services with Affiliates. To the extent that conflicts of interest may arise between us and Affiliates, those conflicts may be resolved in a manner adverse to us or its other stockholders.

These relationships could create, or appear to create, potential conflicts of interest when our Board is faced with decisions that could have different implications for us and Affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public’s perception of us, as well as our relationship with other companies and our ability to enter new relationships in the future, which may have a material adverse effect on our ability to do business.

A7. The dangers inherent in oil and gas operations could expose us to potentially significant losses, costs, or liabilities, and reduce our liquidity.

Oil and gas operations are inherently subject to significant hazards and risks. We process, store, and handle crude oil and condensate, which, under certain circumstances, can be extremely dangerous. Hazards and risks related to the Nixon facility include, but are not limited to, catastrophic events caused by fires, explosions, pressure vessel ruptures, spills, third-party interference, electricity, and mechanical breakdown, any of which could result in interruption or termination of operations, pollution, personal injury and death, or damage to our assets and the property of others.

Offshore operations are also subject to a variety of operating risks peculiar to the marine environment. Although our pipeline assets and leasehold interests in oil and gas wells are inactive, natural disasters and other events, such as hurricanes, can result in blowouts, cratering, explosions, and loss of well control. These hazards can cause injury to persons, loss of life, and damage to property or the environment.

Any of these risks could result in substantial losses to us from a significant decrease in operations, significant additional costs to replace, repair, and insure assets, and from potential civil lawsuits, fines, penalties, and regulatory enforcement proceedings. We may also become subject to more extensive governmental regulation. These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations. These risks could also harm our reputation and business, result in claims against us, and have a material adverse effect on our results of operations and financial condition.

A8. The geographic concentration of our assets creates a significant exposure to the risks of the regional economy and other regional adverse conditions.

Our primary operating assets are in Nixon, Texas in the Eagle Ford Shale, and we market our refined products in a single, relatively limited geographic area. In addition, we have facilities and related onshore pipeline assets in Freeport, Texas, and offshore pipelines and oil and gas properties in the Gulf of Mexico. As a result, our operations are more susceptible to regional economic conditions than our more geographically diversified competitors. Any changes in market conditions, unforeseen circumstances, or other events affecting the area in which our assets are located could have a material adverse effect on our business, financial condition, and results of operations. These factors include, among other things, changes in the economy, weather, demographics, and population.

A9. Competition from companies having greater financial and other resources could materially and adversely affect our business and results of operations.

The refining industry is highly competitive. Our refining operations compete with domestic refiners and marketers in PADD 3 (Gulf Coast), domestic refiners in other PADD regions, and foreign refiners that import products into the U.S. Certain of our competitors have larger, more complex refineries and may be able to realize higher margins per barrel of product produced. Several of our principal competitors are integrated national or international oil companies that are larger and have greater resources than we do and have access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain all our feedstocks from a single supplier. Because of their integrated operations and larger capitalization, larger, more complex refineries may be more flexible in responding to volatile industry or market conditions, such as crude oil and other feedstocks supply shortages or commodity price fluctuations. If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers.

A10. Our insurance policies do not cover all losses, costs, or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.

Our insurance program may not cover all operational risks and costs and may not provide sufficient coverage in the event of a claim. We do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance, failure by one or more of our insurers to honor its coverage commitments for an insured event, or losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition, and results of operations.

There is finite capacity in the commercial insurance industry engaged in underwriting energy industry risk, and factors impacting cost and availability include: (i) losses in our industries, (ii) natural disasters, (iii) specific losses incurred by us, and (iv) inadequate investment returns earned by the insurance industry. If the supply of commercial insurance is curtailed, we may not be able to continue our present limits of insurance coverage, obtain sufficient insurance capacity to adequately insure our risks, or we may be unable to obtain and maintain adequate insurance at a reasonable cost. There is no assurance that our insurers will renew their insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses or cancellation of insurance policies could have a material adverse effect on our business, financial condition, and results of operations.

A11. Our ability to use NOL carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

Under IRC Section 382, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years).

Blue Dolphin experienced ownership changes in 2005 because of a series of private placements, and in 2012 because of a reverse acquisition. The 2012 ownership change limits our ability to utilize NOLs following the 2005 ownership change that were not previously subject to limitation. Limitations imposed on our ability to use NOLs to offset future taxable income could cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect, and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes. NOLs generated after the 2012 ownership change are not subject to limitation. If the IRS were to challenge our NOLs in an audit, we cannot assure that we would prevail against such challenge. If the IRS were successful in challenging our NOLs, all or some portion of our NOLs would not be available to offset any future consolidated income, which would negatively impact our results of operations and cash flows. Certain provisions of the Tax Cuts and Jobs Act, enacted in 2017, may also limit our ability to utilize our net operating tax loss carryforwards.

At December 31, 2023, management determined that realization of the deferred tax assets from NOLs is more likely than not based on positive evidence that was evaluated, including recent earnings history and expectations for future taxable income. Based on management’s evaluation, we reversed the previously recorded valuation allowances against the deferred tax assets as of December 31, 2023.

A12 . We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

B. Downstream and Midstream Operations

B1. Refining margins, which are affected by commodity prices and refined product demand, are volatile, and a reduction in refining margins will adversely affect the amount of cash we will have available for working capital.

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship between our crude oil and condensate acquisition costs, the commodity prices at which we ultimately sell our refined products, and the volume of refined products that we sell, all of which depend upon numerous factors beyond our control. The commodity prices at which we sell our refined products are strongly influenced by the commodity price of crude oil. If crude oil commodity prices increase, our ‘refinery operations’ business segment margins will fall unless we can pass along these commodity price increases to our wholesale customers. Increases in the selling prices for refined products typically trail the rising crude oil cost and may be difficult to implement when crude oil costs increase dramatically over a short period. Sharp decreases in refined product market demand, such as the record low demand that occurred because of widespread COVID-19 related travel restrictions, can adversely affect our refining margins.

B2. The commodity price volatility of crude oil, other feedstocks, refined products, and fuel and utility services may have a material adverse effect on our earnings, cash flows, and liquidity.

Crude oil refining is primarily a margin-based business. To improve margins, we must maximize yields of higher value finished petroleum products and minimize costs of feedstocks and operating expenses. When the spread between these commodity prices decreases, our margins are negatively affected. Although an increase or decrease in the commodity price for crude oil and other feedstocks generally results in a similar increase or decrease in commodity prices for finished petroleum products, typically there is a time lag between the two. The effect of crude oil commodity price changes on our finished petroleum product commodity prices therefore depends, in part, on how quickly and how fully the market adjusts to reflect these changes. Unfavorable margins may have a material adverse effect on our earnings, cash flows, and liquidity.

The markets and commodity prices for crude oil and condensate and our finished products have historically been volatile, are likely to continue to be volatile, and depend on factors beyond our control. These factors include:

• The level of domestic and offshore production.
• The availability of crude oil and U.S. and global demand for this commodity.
• A general downturn in economic conditions.
• The impact of weather, including abnormally mild or extreme winter or summer weather that cause lower or higher energy usage for heating or cooling purposes, respectively, or extreme weather that may disrupt our operations or related upstream or downstream operations.
• Actions taken by foreign oil and gas producing and importing nations, including the ability or willingness of OPEC and OPEC+ to set and maintain pricing and production levels for oil, which, for example, had a pronounced effect on global commodity prices for crude oil and the volatility thereof in 2020 during the onset and spread of the COVID-19 pandemic.
• The availability of local, intrastate, and interstate transportation systems.
• U.S. and global economic conditions, including inflationary pressures, further increases in interest rates, and a general economic slowdown or recession.
• geopolitical tensions, including conflicts and war, such as ongoing military conflicts in Ukraine and Israel and escalations in the Middle East.
• The availability and marketing of competitive fuels.
• The extent of governmental regulation and taxation.

B3. Our future success depends on our ability to acquire sufficient levels of crude oil to operate the Nixon refinery on favorable terms when needed.

Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. During 2022 and 2023, we operated under a crude supply agreement with Tartan. Related to the Tartan Crude Supply Agreement, Tartan stored crude oil at the Nixon facility under a terminal services agreement. In a letter dated October 31, 2023, Tartan provided LE and NPS the required 60 days’ notice of its intention to terminate the Tartan Crude Supply Agreement and terminal services agreement. The effective date of the termination was December 31, 2023. On December 29, 2023, we entered a new crude supply agreement with MVP, effective January 1, 2024. This agreement provides a firm source of light-sweet Eagle Ford crude oil to the Nixon facility under improved credit terms, and management believes that MVP can provide us with adequate amounts of crude oil and condensate for the foreseeable future. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (5)” to our consolidated financial statements for additional information regarding the crude supply agreement with MVP.

Under the volume-based Tartan Crude Supply Agreement, Tartan was to deliver 24.8 million net bbls of crude oil. For the twelve months ended December 31, 2023 and 2022, volume delivered under the Tartan Crude Supply Agreement, as a percentage of the total net bbls of crude oil deliverable, was 71.0% and 54.8%, respectively. During the twelve months ended December 31, 2023, substantially all our crude was sourced from Tartan. During the twelve months ended December 31, 2022, all our crude oil was sourced from Tartan.

Our financial health has been materially and adversely affected by significant current debt, certain of which is in default, historical net losses, working capital deficits, and margin volatility. If we are required to obtain our crude oil and condensate without the benefit of a long-term crude supply agreement, our exposure to the risks associated with volatile crude oil prices may increase, crude oil transportation costs may increase, and our liquidity may be reduced. Similarly, if producers experience crude supply constraints and increased transportation costs, our crude acquisition costs may rise even further, or we may not receive sufficient mounts to meet our needs, which could result in refinery downtime and could materially affect our business, financial condition, and results of operations.

Given the large dollar amount required to make crude oil purchases, liquidity constraints could cause us to delay purchases of crude oil or otherwise acquire less than the desired amounts. This, in turn, could cause us to operate the Nixon facility at a lower rate on a bpd basis to meet customer demand. During the twelve-month periods ended December 31, 2023 and 2022, the refinery experienced 0 and 4 days of downtime due to lack of crude associated with cash constraints. Failing to operate the Nixon facility at the desired run rate, or at all, could adversely affect our profitability and cash flows.

B4. Downtime at the Nixon refinery could result in lost margin opportunity, increased maintenance expense, increased inventory, and a reduction in cash available for payment of our obligations.

The Nixon refinery periodically undergoes planned shutdowns to repair, restore, refurbish, or replace refinery equipment. Occasionally, unplanned temporary shutdowns occur. Unplanned downtime can occur for a variety of reasons; however, common reasons for unplanned downtime include repair/replacement of disabled equipment, crude deficiencies associated with cash constraints, high temperatures, weather, and power outages. We are particularly vulnerable to operation disruptions because all our refining operations occur at a single facility. Any scheduled or unscheduled downtime results in lost margin opportunity, reduced refined products inventory, and potential increased maintenance expense, all of which could reduce our ability to meet our payment obligations.

During the twelve-month period ended December 31, 2023, the refinery experienced 12 days of downtime – 9 days for maintenance and repairs and 3 days for a turnaround. During the twelve-month period ended December 31, 2022, the refinery experienced 22 days of downtime – 13 days for maintenance, 5 days due to an unnamed winter ice storm, and 4 days due to lack of crude associated with cash constraints. Any scheduled or unscheduled downtime will result in lost margin opportunity, potential increased maintenance expense, and a reduction of refined products inventory, which could reduce our ability to meet our payment obligations.

B5. Potential impairment in the carrying value of long-lived assets could negatively affect our operating results.

We have a significant amount of long-lived assets on our consolidated balance sheet. Under generally accepted accounting principles, long-lived assets are required to be reviewed for impairment annually or whenever adverse events or changes in circumstances indicate a possible impairment. If business conditions or other factors cause the undiscounted estimated pretax cash flows for long-lived assets to fall below their carrying value, we may be required to record non-cash impairment charges. Events and conditions that could result in impairment in the value of our long-lived assets include lower realized refining margins, decreased refinery production, other factors leading to a reduction in expected long-term sales or profitability, or significant changes in the manner of use for the assets or the overall business strategy.

We continuously monitor our assets for impairment and optimization opportunities. During the twelve months ended December 31, 2023 and 2022, we recorded an additional impairment of $1.6 million and $0.1 million, respectively, due to an additional change in the timing of decommissioning our offshore pipeline and platform assets. An additional impairment may be required in future periods if instabilities in the market continue long-term, losses continue to be material, or as new opportunities arise, such as reconfiguration of the Nixon refinery into a renewable fuels facility.

Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows. As a result, there can be no assurance that the estimates and assumptions made for purposes of our impairment analysis will prove to be an accurate prediction of the future. Should our assumptions significantly change in future periods, it is possible we may later determine the carrying values of our refinery and facilities assets exceed the undiscounted estimated pretax cash flows, which would result in a future impairment charge.

B6. We may have capital needs for which internally generated cash flows and external financing are inadequate. Affiliates may, but are not required to, fund our working capital requirements in such instances.

We have historically relied on Affiliates for funding when revenue from operations and availability under bank facilities were insufficient to meet our liquidity and working capital needs. During such times, Affiliate borrowings are reflected in our consolidated balance sheets in accounts payable, related party, or long-term debt, related party. Accounts payable, related party totaled approximately $0.9 million and $0.2 million at December 31, 2023 and 2022, respectively. Accounts payable, related party at December 31, 2023 reflected tank rental fees owed by LE to Ingleside under the LE Amended and Restated Master Services Agreement plus amounts owed to LTRI for previously purchased refinery equipment. Accounts payable, related party at December 31, 2022 reflected amounts owed to LTRI for previously purchased refinery equipment. No amounts for either period related to Affiliate borrowings for working capital.

At December 31, 2023 and 2022, long-term debt, related party (current portion) totaled $0.0 and $5.2 million, respectively; at the same balance sheet date, long-term debt, related party (noncurrent portion) totaled $4.0 million and $0.0, respectively. At December 31, 2023 and 2022, accrued interest payable, related party (current and noncurrent portions) totaled $1.3 million and $4.1 million, respectively. Long-term debt, related party and accrued interest payable, related party at December 31, 2023 reflected amounts BDPL owed to LEH under under the BDPL-LEH Loan Agreement, the proceeds of which were used as working capital. Long-term debt, related party and accrued interest payable, related party at December 31, 2022 reflected amounts Blue Dolphin owed to LEH under the June LEH Note and amounts BDPL owed to LEH under the BDPL-LEH Loan Agreement. Pursuant to a payoff letter dated March 31, 2023, Blue Dolphin fully satisfied the debt associated with the June LEH Note.

If we are unable to generate sufficient cash flows from operations, obtain additional external financing, or secure sufficient liquidity from Affiliates, we may not be able to meet our short- and long-term working capital needs. Our short-term working capital needs are primarily related to: (i) purchasing crude oil and condensate to operate the Nixon refinery, (ii) reimbursing LEH for direct operating expenses and paying the LEH operating fee under the Third Amended and Restated Operating Agreement, (iii) servicing debt, (iv) meeting regulatory compliance mandates, and (v) maintaining the Nixon facility through capital expenditures. Our long-term working capital needs are primarily related to repayment of long-term debt obligations. There can be no assurance that Affiliates will continue to fund our working capital requirements. If we are unable to generate sufficient working capital or raise additional capital on acceptable terms, or at all, we may not, in the short term, be able to purchase crude oil and condensate or meet debt payment obligations. In the long term, we may not be able to withstand business disruptions, such as from COVID-19, or execute our business strategy. We may have to consider other options, such as selling assets, raising additional debt or equity capital, seeking bankruptcy protection, or ceasing operations.

B7. Our business may suffer if any of the executive officers or other key personnel discontinue employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain productivity.

Our future success depends on the services of the executive officers and other key personnel and on our continuing ability to recruit, train and retain highly qualified personnel in all areas of our operations. In particular, Jonathan Carroll currently serves as our principal executive, principal financial and principal accounting officer. We are highly dependent on his continued services to execute our business plan and strategy. Furthermore, our operations require skilled and experienced personnel with proficiency in multiple tasks. Competition for skilled personnel with industry-specific experience is intense, and the loss of these executives or personnel could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business could be materially adversely affected.

B8. Loss of business from, or the bankruptcy or insolvency of, one or more of our significant customers, one of which is an Affiliate, could have a material adverse effect on our financial condition, results of operations, liquidity, and cash flows.

We have bulk term contracts in place with most of our customers, including month-to-month, six months, and up to one-year terms. Certain of our contracts require our customers to prepay and us to sell fixed quantities and/or minimum quantities of finished and intermediate petroleum products. Many of these arrangements are subject to periodic renegotiation on a forward-looking basis, which could result in higher or lower relative commodity prices on future sales of our refined products.

Our customers have a variety of suppliers to choose from. As a result, they can make substantial demands on us, including demands for more favorable product pricing or contractual terms. Our ability to maintain strong relationships with our principal customers is essential to our future performance. Our operating results could be harmed if a key customer is lost, reduces their order quantity, requires us to reduce our commodity prices, is acquired by a competitor, or suffers financial hardship. Additionally, our profitability could be adversely affected if there is consolidation among our customer base and our customers command increased leverage in negotiating commodity prices and other terms of sale. We could decide not to sell our refined products to a certain customer if, because of increased leverage, the customer pressures us to reduce our pricing such that our gross profits are diminished, which could result in a decrease in our revenue. Consolidation may also lead to reduced demand for our products, replacement of our products by the combined entity with those of our competitors, and cancellations of orders, each of which could harm our operating results. Loss of business from, or the bankruptcy or insolvency of, one or more of our major customers could similarly affect our financial condition, results of operations, liquidity, and cash flows.

One of our significant customers is LEH, an Affiliate. LEH purchases our jet fuel under an Amended and Restated Jet Fuel Sales Agreement and sells the jet fuel to the DLA under preferential pricing terms due to its HUBZone certification. The Affiliate accounted for 31.7% and 35.7% total revenue from operations for the twelve months ended December 31, 2023 and 2022, respectively. The Affiliate represented $4.2 million and $0 in accounts receivable, related party at December 31, 2023 and 2022, respectively.

B9. We are dependent on third parties for the transportation of crude oil and condensate into and refined products out of our Nixon facility. If these third parties become unavailable to us, our ability to process crude oil and condensate and sell refined products to wholesale markets could be materially and adversely affected.

We rely on trucks for the receipt of crude oil and condensate into and the sale of refined products out of our Nixon facility. Since we do not own or operate any of these trucks, their continuing operation is not within our control. If any of the third-party trucking companies that we use, or the trucking industry in general, become unavailable to transport crude oil, condensate, and/or our refined products because of acts of God, accidents, government regulation, terrorism or other events, our revenue and net income would be materially and adversely affected.

B10. Our suppliers source a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale and may experience interruptions of supply from that region.

Our suppliers source a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale. Consequently, we may be disproportionately exposed to the impact of delays or interruptions of supply from that region caused by transportation capacity constraints, curtailment of production, unavailability of equipment, facilities, personnel or services, significant governmental regulation, severe weather, plant closures for scheduled maintenance, or the interruption of oil or natural gas being transported from wells in that area.

B11. Our refining operations and customers are primarily located within the Eagle Ford Shale and changes in the supply/demand balance in this region could result in lower refining margins.

Our primary operating assets are in Nixon, Texas in the Eagle Ford Shale, and we market our refined products in a single, limited geographic area. Therefore, we are more susceptible to regional economic conditions than our more geographically diversified competitors. Should the supply/demand balance shift in our region due to changes in the local economy, an increase in refining capacity or other reasons, resulting in supply in the PADD 3 (Gulf Coast) region to exceed demand, we would have to deliver refined products to customers outside of our current operating region and thus incur considerably higher transportation costs, resulting in lower refining margins.

B12. Severe weather or other events affecting our facilities, or those of our vendors, suppliers, or customers could have a material adverse effect on our liquidity, business, financial condition, and results of operations.

Our operations are subject to all the risks and operational hazards inherent in receiving, handling, storing, and transferring crude oil and petroleum products. These risks include damages to facilities, related equipment and surrounding properties caused by severe weather (such as extreme cold or hot temperatures, hurricanes, floods, and other natural disasters) or other events (such as equipment malfunctions, mechanical or structural failures, explosions, fires, spills, or acts of terrorism) and can occur at our facilities or at third-party facilities on which our operations are dependent. Severe weather or other events could cause significant damage or destruction to our assets or the temporary or permanent shut-down of our operations. If we are unable to operate, our liquidity, business, financial condition, and results of operations could be materially affected.

B13. Our renewable energy strategy may not materialize or underperform expectations.

Our business strategy to leverage existing infrastructure and capitalize on green energy growth depends on our ability to find commercial partners and government loans as vehicles to enter the renewable energy space. The plans are subject to business, economic and competitive uncertainties, many of which are beyond our control. Additionally, we may be forced to develop or implement new technologies at substantial costs to achieve our strategy. These uncertainties and costs could cause us to not be able to fully implement or realize the anticipated results and benefits of our business strategy.

C. Legal, Government, and Regulatory

C1. Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities.

Our operations are subject to a variety of federal, state, and local environmental laws and regulations relating to the protection of the environment and natural resources, including those governing the emission or discharge of pollutants into the environment, product specifications and the generation, treatment, storage, transportation, disposal, and remediation of solid and hazardous wastes. Violations of these laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns. These and further actions could restrict or limit operations as currently conducted at the Nixon Facility.

In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of laws and regulations, or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. Expenditures or costs for environmental compliance could have a material adverse effect on our results of operations, financial condition, and profitability. The Biden administration has made, and is expected to make additional changes to applicable regulations, and in each case we expect changes to be more stringent than those of the prior administration.

The Nixon facility operates under several federal and state permits, licenses, and approvals with terms and conditions that contain a significant number of prescriptive limits and performance standards. These permits, licenses, approvals, limits, and standards require a significant amount of monitoring, record keeping and reporting to demonstrate compliance with the underlying permit, license, approval, limit or standard. Non-compliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties, and injunctive relief. Additionally, there may be times when we are unable to meet the standards and terms and conditions of our permits, licenses, and approvals due to operational upsets or malfunctions, which may lead to the imposition of fines and penalties or operating restrictions that may have a material adverse effect on our ability to operate our facilities, and accordingly our financial performance.

C2. We are subject to strict laws and regulations regarding personnel and process safety, and failing to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition, and profitability.

We are subject to the requirements of OSHA, and comparable state statutes that regulate the protection, health, and safety of workers, and the proper design, operation, and maintenance of our equipment. In addition, OSHA and certain other environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to personnel and state and local governmental authorities. Failing to comply with these requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations, financial condition, and cash flows.

C3. The impact of current and future sanctions imposed by governments and other authorities, including the U.S., the European Union, and the United Kingdom in response to geopolitical tensions, including military conflicts in Ukraine and Israel and escalations in the Middle East.

In February 2022, Russia initiated significant military action against Ukraine. In response, the U.S. and certain other countries imposed significant sanctions and export controls against Russia. In October 2023, Hamas launched a surprise attack on Israel. In response, the U.S. and certain other countries imposed sanctions against Hamas and key Hamas terrorist group members. The U.S. and certain other countries could impose further sanctions, trade restrictions, and other retaliatory actions should these conflicts continue or worsen. It is not possible to predict the broader consequences of these conflicts, including related geopolitical tensions, the measures and retaliatory actions taken by the U.S. and other countries, counter measures or retaliatory actions by Russia or Hamas in response (e.g., potential cyberattacks or the disruption of energy exports). Such consequences are likely to cause regional instability, geopolitical shifts, and could materially adversely affect global trade, currency exchange rates, regional economies, and the global economy. While it is difficult to predict the impact of any of the foregoing, these conflicts and actions taken in response could increase our costs for crude oil, disrupt our supply chain, reduce our sales and earnings, impair our ability to raise additional capital when needed on acceptable terms, if at all, or otherwise adversely affect our business, financial condition, and results of operations.

C4. General U.S. economic, political, or regulatory developments, including those related to recession, inflation, interest rates, or governmental policies relating to refined petroleum products, crude oil, or taxation could adversely affect our business, operating results, and financial condition.

U.S. economic slowdowns may have serious negative consequences for our business and operating results because our performance is subject to domestic economic conditions and their impact on levels of consumer spending (e.g., consumer airline travel relating to jet fuel). Some of the factors affecting consumer spending include unemployment rates, consumer debt levels, recession, inflation rates, net worth reductions based on declines in equity markets and residential real estate values, interest rates for mortgages and other loans, taxation, energy prices, consumer confidence, and other macroeconomic factors. Political instability and health crises, such as COVID-19, can also impact the global economy and decrease worldwide demand for oil and refined products. During periods of economic weakness or uncertainty, current or potential customers may travel less, reduce, or defer purchases, go out of business, or have insufficient funds to buy or pay for our products and services. Moreover, a financial market crisis may have a material adverse impact on financial institutions and limit access to capital and credit. This could, among other things, make it more difficult for us to obtain (or increase our cost of obtaining) capital and financing for our operations. Our access to additional capital may not be available on terms acceptable to us or at all.

Because our refinery is located in the Gulf Coast Region, we primarily market our refined products in a relatively limited geographic area. As a result, we are more susceptible to regional economic conditions compared to our more geographically diversified competitors, and any unforeseen events or circumstances that affect the Gulf Coast Region could also materially and adversely affect our revenues and cash flows. Primary factors include, among other things, changes in the economy, weather conditions, demographics and population, increased supply of refined products from competitors and reductions in the supply of crude oil or other feedstocks. In the event of a shift in the supply/demand balance in the Gulf Coast Region due to changes in the local economy, an increase in aggregate refining capacity or other reasons, resulting in supply exceeding the demand in the region, our refinery may have to deliver refined products to more customers outside of the Gulf Coast Region and thus incur considerably higher transportation costs, resulting in lower refining margins, if any.

C5. Penalty assessments by regulatory agencies, such as BOEM, BSEE, OSHA, and TCEQ for failing to meet regulatory requirements could adversely affect our business, operating results, and financial condition.

BOEM Supplemental Pipeline Bonds. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the statutory bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning pipelines and platforms at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM.

Historically, BDPL maintained $0.9 million in pipeline bonds with BOEM to decommission its trunk pipeline offshore in federal waters. In March 2018, BOEM ordered BDPL to provide additional financial assurance totaling approximately $4.8 million for five (5) existing pipeline rights-of-way, an increase of approximately $3.9 million. In June 2018, BOEM issued BDPL INCs for each right-of-way that failed to comply. BDPL appealed the INCs to the IBLA. Although the IBLA granted multiple extension requests, the Office of the Solicitor of the U.S. Department of the Interior indicated that BOEM would not consent to further extensions. The solicitor’s office signaled that BDPL’s adherence to decommissioning its offshore pipelines and platform would likely help in future discussions with BOEM related to the INCs. Fulfilling abandonment obligations related to the subject assets will significantly reduce or eliminate the amount of supplemental pipeline bonds required by BOEM, which may serve to partially or fully resolve the INCs.

BDPL’s pending appeal of the BOEM INCs does not relieve BDPL of its obligations to provide additional financial assurance or of BOEM’s authority to impose financial penalties. There can be no assurance that we will be able to meet additional supplemental pipeline bond requirements. If BDPL is required by BOEM to provide significant additional supplemental pipeline bonds or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. We cannot predict the outcome of the supplemental pipeline bond INCs. Accordingly, we did not record a liability on our consolidated balance sheets as of December 31, 2023 and 2022. At both December 31, 2023 and 2022, BDPL maintained approximately $0.9 million in pipeline rights-of-way surety bonds issued to BOEM through RLI Corp. ("RLI"). However, as noted below, RLI desires to reduce its risk profile related to BDPL's bonds. Of the pipeline rights-of-way bonds, $0.7 million was credit-backed and $0.2 million was cash-backed.

RLI Surety Bonds. Blue Dolphin currently has several surety bonds through RLI as required by different regulatory agencies, including BOEM and the Railroad Commission of Texas. The bonds total approximately $1.25 million in the aggregate, of which $0.2 million is collateralized in cash. In June, July, and December 2023, RLI demanded Blue Dolphin provide additional cash collateral or a letter of credit totaling approximately $1.0 million or provide bond exonerations and replacement bonds. Although Blue Dolphin received a proposal from another surety to replace the RLI bonds at a 50% collateral requirement, management was hopeful Blue Dolphin and RLI could reach an understanding whereby the existing bonds could be maintained until BDPL completed decommissioning of the subject assets. Abandonment of BDPL’s offshore pipeline and platform assets will eliminate the need for all BOEM supplemental pipeline bonds, reducing the amount of surety bonds held by RLI from $1.25 million to $0.25 million. On February 19, 2024, RLI filed suit against Blue Dolphin, BDPL, and BDEX seeking an injunction for the payment of approximately $1.0 million of additional collateral for the bonds.

BSEE Offshore Platform Inspections and Decommissioning Obligations. BDPL has pipelines and platform assets subject to BSEE’s idle iron regulations. Idle iron regulations require lessees and rights-of-way holders to permanently abandon and/or remove platforms and other structures when they are no longer useful for operations. Until such structures are abandoned or removed, lessees and rights-of-way holders are required to inspect and maintain the assets in accordance with regulatory requirements.

Platform Inspections. We are required by BSEE to perform annual structural inspections of our offshore platform, as well as to perform monthly platform checks of navigational aids, fog horns, and lifesaving equipment. In March 2023, BSEE issued BDPL an INC for failing to perform the required 2021 and 2022 structural surveys for the GA-288C platform and for failing to provide BSEE with such survey results. In April 2023, BSEE granted BDPL an extension for completing the required platform inspection until May 30, 2023. Although BDPL requested a second extension, BSEE denied BDPL’s request. BDPL completed the platform inspection on August 26, 2023 and submitted the survey report to BSEE on September 6, 2023. Because BDPL failed to comply with the INC within the allotted timeframe, BSEE proposed an administrative civil penalty of approximately $0.2 million on October 24, 2023. The proposed administrative civil penalty was finalized on January 26, 2024, for $0.2 million. We recorded a liability for the maximum proposed amount of $0.2 million on our consolidated balance sheets within accrued expenses and other current liabilities as of December 31, 2023. BDPL filed an appeal to the civil penalty on March 25, 2024.

Decommissioning Obligations. Because our pipelines and facilities assets have been inactive for an extended period, BOEM mandated that they be decommissioned. In October 2023, management met BSEE to discuss BDPL’s path forward for meeting decommissioning requirements. Management worked with a consultant to develop a decommissioning plan, and BDPL submitted its decommissioning plan to the agency in November 2023. Although the decommissioning of these assets was delayed due to cash constraints associated with historical net losses and the impact of COVID-19, a significant portion of the decommissioning project was completed from late December 2023 to mid-February 2024. Additional work is planned for the second quarter of 2024. Based on resource availability and projected weather conditions, we believe decommissioning and remediation of all associated INCs will be completed by the end of the second quarter 2024. However, BDPL’s work plan does not relieve BDPL of its obligations to comply with BSEE’s mandate or BSEE’s authority to impose financial penalties. Further, there can be no assurance that BDPL can complete anticipated work or predict the outcome of BSEE INCs. Accordingly, we did not record a liability related to potential penalties on our consolidated balance sheets as of December 31, 2023 and 2022. Due to BDPL’s failure to comply with BSEE requirements, BDPL could still be subject to regulatory oversight and enforcement, including but not limited to failing to correct an INC, civil penalties, and revocation of BDPL’s operator designation, which could have a material adverse effect on our earnings, cash flows, and liquidity. At December 31, 2023 and 2022, BDPL maintained $4.5 million and $3.7 million, respectively, in AROs related to the abandonment of these assets, which amount does not include potential penalties.

OSHA Settlement Agreement. In September 2022, we entered into an Informal Settlement Agreement with OSHA related to process safety management violations at the Nixon refinery. Under the agreement, we paid penalties totaling $0.05 million in November 2022. We remediated a significant portion of identified violations before December 31, 2022. We remediated the remaining violations on a progressive schedule by April 2023.

TCEQ Proposed Agreed Order. In October 2021, LRM received a proposed agreed order from the TCEQ for alleged solid and hazardous waste violations discovered during an investigation from January to March 2020. The proposed agreed order assessed an administrative penalty of $0.4 million and identified actions needed to correct the alleged violations. In September 2023, TCEQ presented its final penalty offer of $0.35 million, which LRM accepted. Although LRM believes the penalty matter is resolved, LRM expects to continue working with TCEQ to remediate certain open items fully. At December 31, 2023, we reflected approximately $0.4 million related to this matter on our consolidated balance sheets within accrued expenses and other current liabilities.

C6. Our estimates of future AROs related to our pipeline and facilities assets may increase.

We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and seabeds. We based asset retirement cost estimates on regulatory requirements and then current market rates for decommissioning and removal of assets with our given structural and water depth specifications. Estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. In addition, dive operation market rates are subject to fluctuations based on season, fuel costs, insurance rates, equipment availability, and industry changes, and actual work performed is subject to cost overruns due to unforeseen events and conditions, such as bad weather. A significant change in any of these factors could increase our ARO liability, which could have a material adverse effect on our business, financial condition, and results of operations.

C7. We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas ("HCAs"), which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

• Perform ongoing assessments of pipeline integrity.
• Identify and characterize applicable threats to pipeline segments that could impact an HCA.
• Improve data collection, integration, and analysis.
• Repair and remediate the pipeline as necessary.
• Implement preventative and mitigating actions.

In addition, certain states have also adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. These requirements could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in us incurring increased operating costs that could be significant and have a material adverse effect on our financial position or results of operations. Additionally, we are subject to periodic inspections and audits regarding these requirements. Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could result in our incurring increased operating costs that could have a material adverse effect on our financial position or results of operations.

C8. Regulatory changes, as well as proposed measures that are reasonably likely to be enacted, related to greenhouse gas emissions, climate change, and an ongoing desire to transition to greater renewable energy solutions could require us to incur significant costs or could result in a decrease in demand for our refined products, which could adversely affect our business.

Scientific studies conclusively show that, in the absence of human intervention, the rate of increase of carbon dioxide in the atmosphere will significantly increase in the next 100 years. This increase in carbon dioxide has enhanced the Earth’s natural greenhouse effect, resulting in global warming. Higher concentrations of greenhouse gases (including carbon dioxide, methane, and nitrous oxides) in the atmosphere can produce changes in climate with significant physical effects, including increased frequency and severity of storms, floods, and other extreme weather events that could affect our operations. Increased concern over the effects of climate change have begun to affect our competition and customers’ energy strategies, consumer consumption patterns, and government and private sector alternative energy initiatives. More aggressive efforts by governments and non-governmental organizations to put in place laws requiring or otherwise driving reductions in greenhouse gas emissions appear likely and any such future laws and regulations could result in increased compliance costs or additional operating restrictions to us and our customers, and any increase in the prices of refined products resulting from such increased costs, greenhouse gas cap-and-trade programs or taxes on greenhouse gases, could result in reduced demand for our refined petroleum products. Additionally, changing customer sentiment towards renewable and sustainable energy products may reduce demand for our products, and an excess of supply over demand could reduce fossil fuel prices. If we fail to stay in step with the pace and extent of the market shift, we could impact future earnings; if we move too fast, we risk investing in technologies, markets, and low-carbon products that will be unsuccessful. These factors could also have a material adverse effect on our business, financial condition, and results of operations.

The Biden Administration has focused on reducing greenhouse gas emissions. In February 2021, the U.S. rejoined the Paris Agreement, and in April 2021 the Biden Administration announced a new U.S. target to achieve a 50% to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030. Also, in August 2022, Congress passed and President Biden signed into law the Inflation Reduction Act of 2022, which includes nearly $370 billion in climate-related provisions that provide funding, programs, and incentives to accelerate the U.S.'s transition to a clean energy economy. The Inflation Reduction Act of 2022 also imposes a tax, or "methane fee," on energy producers that exceed a certain level of methane emissions. On January 26, 2024, the EPA published a proposed rule to implement the methane fee. These and similar regulations could require us to incur costs to monitor, report, and reduce greenhouse gas emissions associated with our operations.

Federal and state requirements to reduce greenhouse gas emissions could result in increased costs to operate and maintain the Nixon facility as well as implement and manage new emission controls and programs. Cap-and-trade places a cap on greenhouse gases and refiners are required to acquire a sufficient number of credits to cover emissions from their refinery and in-state sales of gasoline and diesel. Similarly, low carbon fuel standards require an established percentage reduction in the carbon intensity of gasoline and diesel by a specified time period. Compliance with the low carbon fuel standard is achieved through blending lower carbon intensity biofuels into gasoline and diesel or by purchasing credits. Compliance with each of these programs is facilitated through a market-based credit system. If sufficient credits are unavailable for purchase or refiners are unable to pass through costs to their customers, they must pay a higher price for credits. The Nixon refinery does not produce gasoline or diesel. In the event we do incur increased costs as a result of increased efforts to control greenhouse gas emissions, we may not be able to pass on any of these costs to our customers. Regulatory requirements also could adversely affect demand for the refined petroleum products that we produce. Any increased costs or reduced demand could materially and adversely affect our business and results of operations.

D. Security

D1. A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts, and other armed conflicts involving the U.S. or other countries may adversely affect national and global economies and could prevent us from meeting our financial and other obligations. For example, Russia’s February 2022 invasion of Ukraine and Hamas' October 2023 surprise attack on Israel and resulting sanctions and export controls by the U.S. and other countries could have wide-ranging impacts that have yet to be identified. Given the evolving geopolitical situation, there are many unknown factors and events that could materially impact our operations, which may be temporary or permanent in nature. These tensions also create heightened risk of a terrorist attack or armed conflict involving the U.S. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations or the operations of our customers’ is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

D2. We face various risks associated with increased activism against oil and natural gas companies.

Opposition toward oil and natural gas companies has been growing globally and is particularly pronounced in the U.S. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, such as climate change, sustainability efforts, including environmental justice, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands, delay or cancel certain operations, stop or rescind operating permits, or curtail emissions. Any restrictions or limitations on our business or operations resulting from such opposition could have a material adverse effect on our financial condition and results of operations.

D3. Our business could be negatively affected by cyber security threats.

A cyberattack or similar incident could occur and result in information theft, data corruption, loss of data privacy, operational disruption, damage to our reputation or financial loss. Our industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. Our technologies, systems, networks, or other proprietary information, and those of our vendors, suppliers, and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss, or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial loss from remedial actions, loss of business, disruption of operations, damage to our reputation, or potential liability. Also, computers control nearly all the oil and gas distribution systems in the U.S. and abroad, which are necessary for transporting our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets, and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks.

E. Common Stock

E1. Our stock price has experienced fluctuations and may continue to do so, resulting in a substantial loss in your investment.

The market for our Common Stock has been characterized by volatile prices. As a result, investors in our Common Stock may experience a decrease in the value of their securities, including decreases unrelated to our operating performance or prospects. The market price of our Common Stock is likely to be highly unpredictable and subject to wide fluctuations in response to various factors, many of which are beyond our control. These factors include:

• Quarterly variations in our operating results and achievement of key business metrics.
• Changes in the global economy and the local economies in which we operate.
• Our ability to obtain working capital financing.
• Changes in the federal, state, and local laws and regulations to which we are subject.
• Market reaction to any acquisitions, joint ventures or strategic investments announced by us or our competitors.
• The departure of any of our key executive officers and directors.
• Future sales of our securities.

E2. Increasing attention to environmental, social, and governance (ESG) matters may impact our business.

Increasing attention to ESG matters, including those related to climate change and sustainability, increasing societal, investor and legislative pressure on companies to address ESG matters, may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation or threats thereof, negative impacts on our stock price and access to capital markets, and damage to our reputation. Some investors have been divesting and promoting divestment of or screening out of fossil fuel equities and urging lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Further, voluntary carbon-related and target-setting frameworks have developed, and continue to develop, that limit the ability of certain sectors, including the oil and gas sector, from participating, and may result in exclusion of our equity from being included as an investment option in portfolios. 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, including climate change and climate-related risks (including entities commonly referred to as “raters and rankers”). Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and investment community divestment initiatives, among other actions, may lead to negative investor sentiment toward us and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Additionally, evolving expectations on various ESG matters, including biodiversity, waste, and water, may increase costs, require changes in how we operate and lead to negative shareholder sentiment.

E3. Our stock price may decline due to sales of shares.

Affiliates sales of substantial amounts of our Common Stock, or the perception that these sales may occur, may adversely affect the price of our Common Stock and impede our ability to raise capital through the issuance of equity securities in the future. Affiliates could elect in the future to request that we file a registration statement to them to sell shares of our Common Stock. If Affiliates were to sell a large number of shares into the public markets, Affiliates could cause the price of our Common Stock to decline.

E4. We are authorized to issue up to a total of 20 million shares of our Common Stock and 2.5 million shares of preferred stock; issuance of additional shares would further dilute the equity ownership of current holders and potentially dilute the share price of our Common Stock.

We periodically issue Common Stock to non-employee directors for services rendered to the Board and to Jonathan Carroll pursuant to the Guaranty Fee Agreements. In the past, we have also issued Common Stock, Preferred Stock, convertible securities (such as convertible notes), and warrants in order to raise capital. We believe that it is necessary to maintain a sufficient number of available authorized shares of our Common Stock and Preferred Stock to provide us with the flexibility to issue Common Stock or Preferred Stock for business purposes that may arise as deemed advisable by our Board. These purposes could include, among other things: (i) future stock splits, which may increase the liquidity of our shares; (ii) the sale of stock to obtain additional capital or to acquire other companies or businesses, which could enhance our growth strategy or allow us to reduce debt if needed; and (iii) for other bona fide purposes. Our Board may authorize us to issue the available authorized shares of Common Stock or Preferred Stock without notice to, or further action by, our stockholders, unless stockholder approval is required by law or the rules of the OTCQX. The issuance of additional shares of Common Stock or new shares of Preferred Stock, convertible securities, and/or warrants may significantly dilute the equity ownership of the current holders of our Common Stock, affect the rights of our stockholders, or could reduce the market price of our Common Stock. In addition, the issuance or sale of large amounts of our Common Stock, or the potential for issuance or sale even if they do not actually occur, may have the effect of depressing the market price of our Common Stock.

E5. Shares eligible for future sale pursuant to Rule 144 may adversely affect the market.

From time to time, certain of our stockholders may be eligible to sell all or some of their shares of Common Stock by means of ordinary brokerage transactions in the open market pursuant to Rule 144 promulgated under the Securities Act, subject to certain limitations. In general, pursuant to Rule 144, stockholders who have been non-affiliates for the preceding three months may sell shares of our Common Stock freely after six months subject only to the current public information requirement. Affiliates may sell shares of our Common Stock after six months subject to the Rule 144 volume, manner of sale, current public information, and notice requirements. Any substantial sales of our Common Stock pursuant to Rule 144 may have a material adverse effect on the market price of our Common Stock.

E6. We do not expect to pay cash dividends in the foreseeable future and therefore investors should not anticipate cash dividends on their investment.

Under certain of our secured loan agreements, we are restricted from declaring or paying any dividend on our Common Stock without the prior written consent of the lender. We have historically not declared any dividends on our Common Stock and there can be no assurance that cash dividends will ever be paid on our Common Stock.

E7. We do not currently have a chief financial officer, and failing to maintain effective internal controls in accordance with Section 404(a) of the Sarbanes-Oxley Act could result in material weaknesses in our internal controls and have a material adverse effect on our business and stock price.

As a publicly traded company, we are required to comply with the SEC’s rules implementing Sections 302 and 404(a) of the Sarbanes-Oxley Act, which requires management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of controls over financial reporting. Jonathan Carroll, our Chief Executive Officer, also serves as our principal financial and principal accounting officer. Although we review our internal controls over financial reporting in order to ensure compliance with Section 404 requirements, having a chief financial officer would reduce the likelihood of errors related to the recording, disclosure, and presentation of consolidated financial information in quarterly, annual, and other filings. Material weaknesses could result in an adverse reaction in the financial marketplace due to a loss of investor confidence in the reliability of our financial statements, which ultimately could negatively impact our stock price.

There are inherent limitations in the effectiveness of any control system, including the potential for human error and the possible circumvention or overriding of controls and procedures. Additionally, judgments in decision-making can be faulty and breakdowns can occur because of a simple error or mistake. An effective control system can provide only reasonable, not absolute, assurance that the control objectives of the system are adequately met. Accordingly, management does not expect that the control system can prevent or detect all errors or fraud. Further, projections of any evaluation or assessment of effectiveness of a control system to future periods are subject to the risks that, over time, controls may become inadequate because of changes in an entity’s operating environment or deterioration in the degree of compliance with policies or procedures.

We depend on information technology and systems for various operations (including refinery processes and refined product loading) and for capturing accounting, technical and regulatory data for reporting, analysis, and archiving. Our primary business systems mostly consist of purchased and licensed software programs that integrate with our internal solutions. As of the filing date of this report, our risk assessment process related to cybersecurity includes conducting vulnerability assessments using a combination of internal and third-party capabilities to perform technical assessments, vulnerability scanning, and incident and event monitoring. We are working to establish a thorough, risk-based cybersecurity program aimed at safeguarding our data, along with the data of our customers and partners, and we anticipate that such a program will follow well-organized cybersecurity frameworks under a central control figure.

We did not experience a significant cybersecurity breach or associated expenses, penalties, or settlements for the twelve months ended December 31, 2023 and 2022.

An Affiliate operates and manages all our properties under the Third Amended and Restated Operating Agreement. Our owned facilities have been constructed or acquired over a period of years and vary in age and operating efficiency. We believe that all our properties and facilities are adequate for our operations and that our facilities are adequately maintained. At our corporate headquarters, BDSC leases 7,675 square feet of office space in Houston, Texas. The location and general description of our other properties are described within refinery operations, tolling and terminaling, and inactive operations discussions in “Part I, Item 1. Business”.

See “Part I, Item 1. Business” for additional disclosures related to our properties, leases, decommissioning obligations, and assets pledged as collateral.

In the ordinary course of business, we are involved in legal matters incidental to the routine operation of our business, such as mechanic’s liens and contract-related disputes. We may also become party to lawsuits, administrative proceedings, and governmental investigations, including environmental, regulatory, and other matters. Large, and sometimes unspecified, damages or penalties may be sought from us in some matters and certain matters may require years to resolve. Although we cannot provide assurance, we believe that an adverse resolution of the matters described below would not have a material impact on our liquidity, consolidated financial position, or consolidated results of operations.

Resolved Matters

Pilot Dispute Related to Terminal Services Agreement. Effective May 9, 2019, NPS and Pilot entered into a Terminal Services Agreement, pursuant to which NPS agreed to store jet fuel purchased by Pilot at the Nixon facility. On August 25, 2022, Pilot provided the 60-day notice of its intent to terminate the Terminal Services Agreement, which became effective on October 24, 2022. As of the Terminal Services Agreement termination date, approximately 185,000 bbls of Pilot’s jet fuel remained at the Nixon facility.

On October 28, 2022, Pilot commenced an action and application for a temporary restraining order (“TRO”) against NPS in Harris County District Court (the “Texas Action”). After a hearing on the application on October 28, 2022, Pilot’s application for the TRO was denied the same day. On December 2, 2022, NPS filed its answer in the Texas Action. On December 6, 2022, NPS provided notice under Section 7.206(a) of the Texas Business and Commerce Code ("TBCC") of its intent to sell the remaining inventory of Pilot’s jet fuel at the Nixon facility by January 7, 2023. After negotiations, NPS agreed to forbear from exercising its remedies under the TBCC while the parties explored a potential dispute compromise pursuant to the Pilot Forbearance and Accommodation Agreement, with a forbearance period terminating on February 28, 2023. As part of the Pilot Forbearance and Accommodation Agreement, Pilot paid NPS approximately $1.5 million in January 2023.

On March 31, 2023, NPS and Pilot executed the Pilot Forbearance Amendment, extending the forbearance period and all deadlines in the unresolved Texas Action to June 15, 2023. As part of the Pilot Forbearance Amendment, Pilot paid NPS approximately $1.1 million and $0.2 million in April and June 2023, respectively. The parties also negotiated the sale of all 185,000 bbls of stored jet fuel in April 2023. On June 16, 2023, following the expiration of the Pilot Forbearance and Accommodation Agreement, the parties agreed to extend the deadline for responses to outstanding discovery requests in the Texas Action to August 31, 2023. On August 28, 2023 the parties filed a joint motion to stay this case in anticipation of planned mediation in December 2023 to settle all outstanding disputes.

Pilot Settlement Agreement. Pursuant to the Pilot Settlement Agreement, among other matters addressed, NPS's contract-related dispute related to set-off payments and LRM’s contracted-related dispute involving a revenue-sharing arrangement for storing and selling crude oil with Pilot and Tartan, respectively, were fully resolved, and the parties agreed to mutually release all claims against each other. Further, Pilot and NPS agreed to take such actions as necessary to dismiss the Texas Action. For the avoidance of doubt, all contractual agreements between the Lazarus Entities and Pilot Entities were terminated.

OSHA Settlement Agreement. In September 2022, we entered into an Informal Settlement Agreement with OSHA related to process safety management violations at the Nixon refinery. Under the agreement, we paid penalties totaling $0.05 million in November 2022. We remediated a significant portion of identified violations before December 31, 2022. We remediated the remaining violations on a progressive schedule by April 2023.

Unresolved Matters

BOEM Supplemental Pipeline Bonds. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the statutory bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning pipelines and platforms at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM.

Historically, BDPL maintained $0.9 million in pipeline bonds with BOEM to decommission its trunk pipeline offshore in federal waters. In March 2018, BOEM ordered BDPL to provide additional financial assurance totaling approximately $4.8 million for five (5) existing pipeline rights-of-way, an increase of approximately $3.9 million. In June 2018, BOEM issued BDPL INCs for each right-of-way that failed to comply. BDPL appealed the INCs to the IBLA. Although the IBLA granted multiple extension requests, the Office of the Solicitor of the U.S. Department of the Interior indicated that BOEM would not consent to further extensions. The solicitor’s office signaled that BDPL’s adherence to decommissioning its offshore pipelines and platform would likely help in future discussions with BOEM related to the INCs. Fulfilling abandonment obligations related to the subject assets will significantly reduce or eliminate the amount of supplemental pipeline bonds required by BOEM, which may serve to partially or fully resolve the INCs.

BDPL’s pending appeal of the BOEM INCs does not relieve BDPL of its obligations to provide additional financial assurance or of BOEM’s authority to impose financial penalties. There can be no assurance that we will be able to meet additional supplemental pipeline bond requirements. If BDPL is required by BOEM to provide significant additional supplemental pipeline bonds or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. We cannot predict the outcome of the supplemental pipeline bond INCs. Accordingly, we did not record a liability on our consolidated balance sheets as of December 31, 2023 and 2022. At both December 31, 2023 and 2022, BDPL maintained approximately $0.9 million in pipeline rights-of-way surety bonds issued to BOEM through RLI Corp. ("RLI"). However, as noted below, RLI desires to reduce its risk profile related to BDPL's bonds. Of the pipeline rights-of-way bonds, $0.7 million was credit-backed and $0.2 million was cash-backed.

RLI Surety Bonds. Blue Dolphin currently has several surety bonds through RLI as required by different regulatory agencies, including BOEM and the Railroad Commission of Texas. The bonds total approximately $1.25 million in the aggregate, of which $0.2 million is collateralized in cash. In June, July, and December 2023, RLI demanded Blue Dolphin provide additional cash collateral or a letter of credit totaling approximately $1.0 million or provide bond exonerations and replacement bonds. Although Blue Dolphin received a proposal from another surety to replace the RLI bonds at a 50% collateral requirement, management was hopeful Blue Dolphin and RLI could reach an understanding whereby the existing bonds could be maintained until BDPL completed decommissioning of the subject assets. Abandonment of BDPL’s offshore pipeline and platform assets will eliminate the need for all BOEM supplemental pipeline bonds, reducing the amount of surety bonds held by RLI from $1.25 million to $0.25 million. On February 19, 2024, RLI filed suit against Blue Dolphin, BDPL, and BDEX seeking an injunction for the payment of approximately $1.0 million of additional collateral for the bonds.

TCEQ Proposed Agreed Order. In October 2021, LRM received a proposed agreed order from the TCEQ for alleged solid and hazardous waste violations discovered during an investigation from January to March 2020. The proposed agreed order assessed an administrative penalty of $0.4 million and identified actions needed to correct the alleged violations. In September 2023, TCEQ presented its final penalty offer of $0.35 million, which LRM accepted. Although LRM believes the penalty matter is resolved, LRM expects to continue working with TCEQ to remediate certain open items fully. At December 31, 2023, we reflected approximately $0.4 million related to this matter on our consolidated balance sheets within accrued expenses and other current liabilities.

BSEE Civil Penalty

We are required by BSEE to perform annual structural inspections of our offshore platform, as well as to perform monthly platform checks of navigational aids, fog horns, and lifesaving equipment. In March 2023, BSEE issued BDPL an INC for failing to perform the required 2021 and 2022 structural surveys for the GA-288C platform and for failing to provide BSEE with such survey results. In April 2023, BSEE granted BDPL an extension for completing the required platform inspection until May 30, 2023. Although BDPL requested a second extension, BSEE denied BDPL’s request. BDPL completed the platform inspection on August 26, 2023 and submitted the survey report to BSEE on September 6, 2023. Because BDPL failed to comply with the INC within the allotted timeframe, BSEE proposed an administrative civil penalty of approximately $0.2 million on October 24, 2023. The proposed administrative civil penalty was finalized on January 26, 2024, for $0.2 million. We recorded a liability for the maximum proposed amount of $0.2 million on our consolidated balance sheets within accrued expenses and other current liabilities as of December 31, 2023. BDPL filed an appeal to the civil penalty on March 25, 2024.

Defaults under Secured Loan Agreements. We are currently in default under certain secured loan agreements with third parties and related parties. See “Notes (1), (3), and (10)” to our consolidated financial statements for additional disclosures related to third-party and related-party debt, default on such debt, and the potential effects of such defaults on our business, financial condition, and results of operations. If third parties exercise their rights and remedies due to defaults under our secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

The following discussion and analysis is management’s perspective of our current financial condition and results of operations and should be read in conjunction with “Important Information Regarding Forward-Looking Statements,” “Part I, Item 1A. Risk Factors,” and “Part II, Item 8. Financial Statements and Supplementary Data” included in this report.

This discussion and analysis includes the twelve months ended December 31, 2023 and 2022 and a comparison between such periods. The discussions of the twelve months ended December 31, 2021 and year-to-year comparisons between the twelve months ended December 31, 2022 and 2021 that are not included in this report can be found in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the twelve months ended December 31, 2022, which was filed on April 3, 2023, and such discussions are incorporated by reference into this report.

Overview and Outlook

Company Overview. Blue Dolphin is an independent downstream energy company operating in the Gulf Coast region of the U.S. Operations primarily consist of a light sweet-crude, 15,000-bpd crude distillation tower, and approximately 1.25 million bbls of petroleum storage tank capacity in Nixon, Texas. Blue Dolphin was formed in 1986 as a Delaware corporation and is traded on the OTCQX under the ticker symbol “BDCO.”

Assets are organized into two business segments: 'refinery operations' (owned by LE) and 'tolling and terminaling services' (owned by LRM and NPS). 'Corporate and other' includes Blue Dolphin subsidiaries BDPL (inactive pipeline and facilities assets), BDPC (inactive leasehold interests in oil and gas wells), and BDSC (administrative services). Unless the context otherwise requires, references in this report to "we," "us," "our," or "ours" refer to Blue Dolphin, one or more its consolidated subsidiaries, or all of them taken as a whole. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (4)” to our consolidated financial statements for more information about our business segments.

Jonathan Carroll, our Chief Executive Officer, and an Affiliate together controlled 83% of the voting power of our Common Stock as of the filing date of this report. An Affiliate also operates and manages all Blue Dolphin properties, funds working capital requirements during periods of working capital deficits, guarantees certain of our third-party secured debt, and is a significant customer of our refined products. Blue Dolphin and certain of its subsidiaries are currently parties to various agreements with Affiliates. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (3)” for additional disclosures related to Affiliate agreements, arrangements, and risks associated with working capital deficits.

Going Concern Assessment. Certain conditions and events were noted that initially caused management to evaluate our ability to continue as a going concern. These conditions and events include significant debt either in default or under a forbearance agreement that expired on March 29, 2024 and classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 2023 and current and historical working capital deficits at December 31, 2023. Our current assets totaled $49.3 million, and our current liabilities, excluding the current portion of long-term debt, totaled $16.0 million as of December 31, 2023. Management believes that we have sufficient liquidity to meet our obligations as they become due through the generation of cash flows from operations and liquidation of current working capital amounts for a reasonable period (defined as one year from the issuance of these financial statements). To bolster working capital reserves, management continues efforts to restructure debt obligations and reduce cash requirements. Management acknowledges that uncertainty remains related to future operating margins. However, management has a reasonable expectation of Blue Dolphin's ability to generate adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on our long-term debt. Our audited consolidated financial statements have been prepared assuming we will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business.

Our significant current debt resulted from certain third-party loan agreements being classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2023 and 2022. Excluding accrued interest, we had current debt of $39.4 million and $47.4 million as of December 31, 2023 and 2022, respectively. Our significant current debt at December 31, 2023 consisted of bank debt to Veritex and GNCU.

Business Operations Update. For the twelve months ended December 31, 2023, oil and gas commodity prices were down overall compared to the twelve months ended December 31, 2022. During 2022 and into the first quarter of 2023, the recovery in worldwide demand for petroleum-based transportation fuels, particularly jet fuel, favorably impacted commodity prices while the worldwide supply of those products remained constrained. Although oil and gas commodity prices weakened mid-year amid the growing recession in Europe and inflation concerns worldwide, oil and gas commodity prices rebounded by year end; however, prices settled below the war-driven spike seen during 2022.

Blue Dolphin reported net income of $31.0 million, or $2.08 per share, for the twelve months ended December 31, 2023 on lower refinery throughput, production, and sales volumes compared to the same period a year earlier. We reported net income of $32.9 million, or $2.34 per share, for the twelve months ended December 31, 2022. Our full operating results for the twelve months ended December 31, 2023 and 2022, including operating results by segment, can be found within ‘—Results of Operations.’

We had cash flow from operations of $20.0 million for the twelve months ended December 31, 2023. At December 31, 2023, we had approximately $18.7 in cash and cash equivalents. The components of our liquidity and descriptions of our cash flows, capital investments, and other matters impacting our liquidity and capital resources can be found within ‘—Liquidity and Capital Resources.’

General Trends and Outlook. Many uncertainties remain surrounding the capital, credit, and commodity markets. We expect oil and gas commodity prices to continue to be affected by: (i) global supply and demand, which are generally a function of global economic conditions, inventory levels, production or supply chain disruptions, technological advances, regional market conditions and the actions of OPEC, other significant producers and governments; (ii) transportation capacity, infrastructure constraints, and costs in producing areas; (iii) inflation rates; and (iv) market perceptions based on these variables. It is expected that oil and refined product prices will be volatile for the foreseeable future given the global impact of the evolving macro-economic environment, current geopolitical tensions, including military conflicts in Ukraine and Israel and escalations in the Middle East, supply activity from OPEC and non-OPEC oil producing countries, oil releases from the U.S. Strategic Petroleum Reserve by the Biden Administration, and COVID-19. While it is difficult to predict the ultimate economic impacts of these factors on our operations, we have noted key factors below that impacted our results of operations in 2023 and will likely impact our results of operations during 2024:

• Light crude oil commodity pricing and demand.
• Jet fuel commodity pricing and demand.
• Naphtha commodity pricing and demand.

We do not operate or own assets in Russia, Ukraine, or the Middle East.

Liquidity and Access to Capital Markets. We continue to actively explore additional funding to refinance and restructure debt and further improve working capital. During 2023, we entered into the Veritex First Amended Forbearance Agreement, Veritex Second Amended Forbearance Agreement, Kissick Forbearance Agreement, and LEH Forbearance Agreement. During 2022, we secured $1.5 million in working capital through CARES Act loans and entered into the initial forbearance agreement with Veritex. There can be no assurance that we will be able to raise additional capital on acceptable terms, if at all, or refinance existing debt. If we are unable to refinance or restructure debt, certain of which is currently in default, or forbear or waive defaults and lenders exercise their rights with respect to the debt, we may not, in the short term, be able to purchase crude oil and condensate or meet debt payment obligations. In the long term, we may not be able to manage business disruptions, such as those experienced during the height of the COVID-19 pandemic, or execute our business strategy. We may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing operating.

Changes in Regulations. Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local, and other laws and regulations that are increasing in number and becoming more stringent and complex. These laws and regulations include, among other things, permitting requirements, environmental protection measures such as limitations on methane and other greenhouse gas emissions, and renewable fuels standards. The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the profitability of our assets.

Business Strategy and Accomplishments

Our primary business objectives are to improve our financial profile and refining margins by executing the below strategies, modified as necessary, to reflect changing economic conditions and other circumstances:

Optimize Existing Asset Base. During the twelve months ended December 31, 2023, the Nixon facility improved uptime by 10 days, experiencing 12 days of downtime for compared to 22 days of downtime for the twelve months ended December 31, 2022. Downtime in 2023 related to maintenance and repairs (9 days) and a planned turnaround (3 days); downtime in 2022 related to maintenance and repairs (13 days), weather (5 days), and crude deficiencies associated with cash constraints (4 days). Throughout 2023 management focused on identifying safety and mechanical process improvements to optimize plant operations, particularly given increasing extreme weather impacts.

Improve Operational Efficiencies. Tolling and terminaling revenue increased $1.6 million, or 35.8%, for the twelve months ended December 31, 2023 compared to the twelve months ended December 31, 2022 because of increased tank rental revenue and higher ancillary services fees. Tank rental revenue for the 2023 period increased primarily as a result of April and June payments under the Pilot Forbearance Amendment.

Seize Market Opportunities. In 2021, we announced plans to leverage our existing infrastructure to establish adjacent lines of business, capture growing market opportunities, and capitalize on renewable energy growth. Rising demand for renewable energy is attributable to various factors, including growing public support, U.S. governmental actions to increase energy independence, and environmental concerns related to climate change. Throughout 2023, management had meaningful discussions with potential commercial partners and expects to continue with these efforts in 2024. Reductions or modifications to, or the elimination of, governmental incentives or policies that support renewable energy or the imposition of additional taxes, tariffs, duties, or other assessments on renewable energy projects, could result in, among other things, the lack of a satisfactory market for the development and/or financing of new renewable energy projects and us abandoning the development of renewable energy projects.

Successful execution of our business strategy depends on multiple factors. These factors include (i) having adequate working capital to meet operational needs and regulatory requirements, (ii) maintaining safe and reliable operations at the Nixon facility, (iii) meeting contractual obligations, (iv) having favorable margins on refined products, and (v) collaborating with new partners to develop and finance clean energy projects. Our business strategy involves risks. Accordingly, we cannot assure investors that our plans will be successful. If we are unsuccessful, we would likely have to consider other options, such as selling assets, raising additional debt or equity capital, cutting costs, or otherwise reducing our cash requirements, negotiating with our creditors to restructure our applicable obligations, filing bankruptcy, or ceasing operating. In such a case, the trading price of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

Downstream Operations

Our refinery operations segment consists of the following assets and operations:

Crude Oil and Condensate Supply. Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. During 2022 and 2023, we operated under a crude supply agreement with Tartan. Related to the Tartan Crude Supply Agreement, Tartan stored crude oil at the Nixon facility under a terminal services agreement. In a letter dated October 31, 2023, Tartan provided LE and NPS the required 60 days’ notice of its intention to terminate the Tartan Crude Supply Agreement and terminal services agreement. The effective date of the termination was December 31, 2023. On December 29, 2023, we entered a new crude supply agreement with MVP, effective January 1, 2024. This agreement provides a firm source of light-sweet Eagle Ford crude oil to the Nixon facility under improved credit terms, and management believes that MVP can provide us with adequate amounts of crude oil and condensate for the foreseeable future.

Under the volume-based Tartan Crude Supply Agreement, Tartan was to deliver 24.8 million net bbls of crude oil. For the twelve months ended December 31, 2023 and 2022, volume delivered under the Tartan Crude Supply Agreement, as a percentage of the total net bbls of crude oil deliverable, was 71.0% and 54.8%, respectively. During the twelve months ended December 31, 2023, substantially all our crude was sourced from Tartan. During the twelve months ended December 31, 2022, all our crude oil was sourced from Tartan. At December 31, 2023, accounts payable for crude oil and condensate was $0.

Our financial health has been materially and adversely affected by significant current debt, certain of which is in default, historical net losses, working capital deficits, and margin volatility. If we are required to obtain our crude oil and condensate without the benefit of a long-term crude supply agreement, our exposure to the risks associated with volatile crude oil prices may increase, crude oil transportation costs could increase, and our liquidity may be reduced. Similarly, if producers experience crude supply constraints and increased transportation costs, our crude acquisition costs may rise, or we may not receive sufficient amounts to meet our needs, which could result in refinery downtime and could materially affect our business, financial condition, and results of operations.

Products and Markets. Our market is the Gulf Coast region of the U.S., which is represented by the EIA as Petroleum Administration for PADD 3. We sell our products primarily in the U.S. within PADD 3. Occasionally, we sell refined products to customers that export to other countries, such as naphtha and distillate to Mexico.

The Nixon refinery’s product slate is adjusted based on market demand. We currently produce a single finished product – jet fuel – and several intermediate products, including naphtha, HOBM, and AGO. An Affiliate purchases our jet fuel under an Amended and Restated Jet Fuel Sales Agreement and sells the jet fuel to the DLA under preferential pricing terms due to the Affiliate's HUBZone certification. The product sales agreement with the Affiliate has a one-year term expiring the earliest to occur of March 31, 2024 plus 30-day carryover or delivery of the maximum quantity of jet fuel. Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing.

Customers. Customers for our refined products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston – San Antonio – Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers, including month-to-month, six months, and up to one-year terms. Certain of our contracts require our customers to prepay and us to sell fixed quantities and/or minimum quantities of finished and intermediate petroleum products. Many of these arrangements are subject to periodic renegotiation on a forward-looking basis, which could result in higher or lower relative prices on future sales of our refined products.

Competition. Most of our competitors are larger than us and are engaged on a national or international level in many segments of the oil and gas industry, including exploration and production, gathering and transportation, and marketing. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these business segments. We compete primarily based on cost. Due to the low complexity of our simple “topping unit” refinery, we can be relatively nimble in adjusting our refined products slate because of changing commodity prices, market demand, and refinery operating costs.

Safety and Downtime. We operate the refinery in a manner that is materially consistent with industry safety practices and standards. EPA, OSHA, and comparable state and local regulatory agencies provide oversight for personnel safety, process safety management, and risk management to prevent or minimize the accidental release of toxic, reactive, flammable, or explosive chemicals. Our storage tanks are equipped with leak detection devices. We also have response and control plans in place for spill prevention and emergencies.

The Nixon refinery periodically undergoes planned and unplanned temporary shutdowns. We typically complete a planned turnaround annually to repair, restore, refurbish, or replace refinery equipment. However, the timing of planned turnarounds is adjusted to capitalize on favorable market conditions. Occasionally, unplanned shutdowns occur. Unplanned downtime can occur for a variety of reasons; however, common reasons for unplanned downtime include repair/replacement of disabled equipment, crude deficiencies associated with cash constraints, high temperatures, and power outages.

We are particularly vulnerable to operation disruptions because all our refining operations occur at a single facility. Any scheduled or unscheduled downtime results in lost margin opportunity, reduced refined products inventory, and potential increased maintenance expense, all of which could reduce our ability to meet our payment obligations.

Midstream Operations

Our tolling and terminaling segment consists of the following assets and operations:

Products and Customers. The Nixon facility’s petroleum storage tanks and infrastructure are primarily suited for crude oil and condensate and refined products, such as naphtha, jet fuel, diesel, and fuel oil. Our storage customers are typically from the lower portion of the Texas Triangle (the Houston – San Antonio – Dallas/Fort Worth area). Shipments are received and redelivered from the Nixon facility via third party trucks. Contract terms range from month-to-month to three years.

Operations Safety. Our midstream operations are operated in a manner materially consistent with industry safe practices and standards. These operations are subject to OSHA regulations and comparable state and local regulators. Storage tanks used for terminal operations are designed for crude oil and condensate and refined products, and most are equipped with appropriate controls that minimize emissions and promote safety. Our terminal operations have response and control plans, spill prevention and other programs to respond to emergencies.

Inactive Operations

We own other pipeline and facilities assets and have leasehold interests in oil and gas properties. These assets are inactive. We account for these inactive operations in ‘corporate and other.’ Our pipeline assets have been fully impaired since 2016 and our oil and gas leasehold interests have been fully impaired since 2011. Our pipeline assets and oil and gas leasehold interests had no revenue during the twelve months ended December 31, 2023 and 2022. See “Part I, Item 1. Financial Statements – Note (15)” related to pipelines and platform decommissioning requirements and related risks.

We own other pipeline and facilities assets and have leasehold interests in oil and gas properties. These assets are inactive. We account for these inactive operations in ‘corporate and other.’ Our pipeline assets have been fully impaired since 2016 and our oil and gas leasehold interests have been fully impaired since 2011. Our pipeline assets and oil and gas leasehold interests had no revenue during the twelve months ended December 31, 2023 and 2022. See “Part II, Item 8. Financial Statements and Supplementary Data – Notes (11) and (15)” related to pipelines and platform decommissioning requirements, operations, and related risks.

Pipeline and Facilities Safety. Although our pipeline and facility assets are inactive, they require upkeep and maintenance and are subject to safety regulations under OSHA, PHMSA, BOEM, BSEE, and comparable state and local regulators. We have response and control plans, spill prevention and other programs to respond to emergencies related to these assets.

Results of Operations

A discussion and analysis of the factors contributing to our consolidated financial results of operations is presented below and should be read in conjunction with our financial statements in “Part II, Item 8. Financial Statements and Supplementary Data.” The financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but they should not serve as the only criteria for predicting future performance.

Major Influences on Results of Operations. Our results of operations and liquidity are highly dependent upon the margins that we receive for our refined products. The dollar per bbl commodity price difference between crude oil and condensate (input) and refined products (output) is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. When the spread between these commodity prices decreases, our margins are negatively affected. To improve margins, we must maximize yields of higher-value finished petroleum products and minimize costs of feedstocks and operating expenses. Although an increase or decrease in the commodity price for crude oil and other feedstocks generally result in a similar increase or decrease in commodity prices for finished petroleum products, typically there is a time lag between the two. The effect of crude oil commodity price changes on our finished petroleum product commodity prices therefore depends, in part, on how quickly and how fully the market adjusts to reflect these changes. Unfavorable margins may have a material adverse effect on our earnings, cash flows, and liquidity.

The general outlook for the oil and natural gas industry for the remainder of 2024 remains unclear given uncertainties surrounding general macroeconomic conditions related to inflation, interest rates, and capital and credit markets, geopolitical tensions, including military conflicts in Ukraine and Israel and escalations in the Middle East, and COVID-19. We can provide no assurances that refining margins and demand will remain at current levels.

How We Evaluate Our Operations. Management uses certain financial and operating measures to analyze segment performance. These measures are significant factors in assessing our operating results and profitability and include: refinery operations gross profit (deficit), refining gross profit (deficit) per bbl, tolling and terminaling gross profit (deficit), intercompany processing fees, refinery throughput, production and sales data, and refinery downtime.

Refining Gross Profit (Deficit) per Bbl. We use refining gross profit (deficit) per bbl as a downstream benchmark. This non-GAAP measure supplements presented GAAP financial information. Management uses refining gross profit (deficit) per bbl to analyze our core refining results of operations, assess internal performance against budgeted and forecasted amounts, and evaluate impacts on our financial performance considering potential capital investments. As this non-GAAP measure has important limitations as an analytical tool, it should not be considered a substitute for GAAP financial measures. We believe this measure may help investors, analysts, lenders, and rating agencies analyze our results of operations and liquidity in conjunction with presented GAAP financial results.

Storage Tank Rental Revenue and Ancillary Services Fees. Tolling and terminaling revenue primarily represents storage tank rental fees and ancillary services fees (such as for in-tank blending) associated with customer tank rental agreements. As a result, tank rental revenue and ancillary services fees combined are one of the measures management uses to evaluate the performance of our tolling and terminaling business segment.

Operating Costs and Expenses. We manage operating costs and expenses in tandem with meeting environmental, safety, and regulatory requirements while maintaining the mechanical integrity of our assets. Operating costs and expenses are comprised primarily of labor, repair, other maintenance, and utility costs. Refinery operating expenses generally remain stable across broad ranges of throughput volumes, but they can fluctuate from period to period depending on the mix of activities performed and the timing of those expenses within the reporting period. Tolling and terminaling operating costs and expenses are relatively fixed.

Intercompany processing fees. We have an intercompany tolling agreement in place between LE and LRM related to naphtha throughput volumes moving through the naphtha stabilizer unit at the Nixon facility. Although intercompany transactions are eliminated during consolidation, evaluation of intercompany processing fees provides investors with helpful information related to our tolling and terminaling business segment.

Refinery Throughput, Production, and Sales Data. The revenue generated from the refinery operations business segment primarily depends on the crude oil volumes processed into refined products and the refined products volumes sold to customers. These volumes are affected by the supply and demand of, and demand for, crude oil and refined products in the direct and indirect markets served by our assets, as well as refinery downtime.

Refinery Downtime. The Nixon refinery periodically experiences planned and unplanned temporary shutdowns. Any scheduled or unscheduled downtime results in lost margin opportunity, potential increased maintenance expense, and reduced refined products inventory, which could adversely impact our ability to meet our payment obligations.

Consolidated Results. Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore do not equal the sum of the operating results of our refinery operations and tolling and terminaling business segments.

Twelve Months Ended December 31, 2023 (“2023”) Versus Twelve Months Ended December 31, 2022 (“2022”)

Overview. Net income for 2023 was $31.0 million, or income of $2.08 per share, compared to net income of $32.9 million, or income of $2.34 per share, in 2022. The $1.9 million, or $0.26 per share, decrease in net income between the periods was the result of less favorable refining margins and slightly lower product demand.

Total Revenue from Operations. Total revenue from operations was $396.0 million for 2023 compared to total revenue from operations of $487.5 million for 2022, representing a decrease of 18.8%. The primary drivers of the decrease was lower commodity prices and sales volume, impacting refinery operations. Tolling and terminaling revenue increased 35.8% between the periods as a result of Pilot payments in January under the Pilot Forbearance and Accommodation Agreement and in April and June under the Pilot Forbearance Amendment.

Total Cost of Goods Sold. Total cost of goods sold was $351.4 million for 2023 compared to total cost of goods sold of $441.4 million for 2022, representing a decrease of 20.4%. The decrease related to lower crude acquisition costs associated with lower refinery throughput and lower commodity prices.

Gross Profit. Gross profit totaled $44.7 million for 2023 compared to gross profit of $46.1 million for 2022. Less favorable commodity prices and and slightly lower product demand adversely impacted refinery operations gross profit in 2023 compared to 2022.

General and Administrative Expenses. General and administrative expenses totaled $3.1 million in 2023 compared to general and administrative expenses of $2.9 million in 2022. The $0.2 million, or 7.5%, increase primarily related to higher insurance renewal premiums and legal fees associated with the Pilot dispute.

Depreciation and Amortization. Depreciation and amortization expenses was flat at $2.8 million for both 2023 and 2022.

Total Other Income (Expense). Total other expense in 2023 was flat compared to 2022, totaling $5.9 million for both periods.

(in thousands)

(1) General and administrative expenses within refinery operations include the LEH operating fee, related party, other operating expenses, and accretion of asset retirement obligations.

Downstream Operations. Our refinery operations business segment is owned by LE. Assets within this segment consist of a light sweet-crude, 15,000-bpd crude distillation tower, petroleum storage tanks, loading and unloading facilities, and approximately 56 acres of land. Refinery operations revenue is derived from refined product sales.

2023 Versus 2022

(in thousands)

(1) Fees associated with an intercompany tolling agreement related to naphtha volumes.

Refinery Downtime. The Nixon facility improved uptime by 10 days in 2023, experiencing 12 days of downtime compared to 22 days of downtime in 2022. Refinery downtime in 2023 related to maintenance and repairs (9 days) and a planned turnaround (3 days); downtime in 2022 related to maintenance and repairs (13 days), weather (5 days), and crude deficiencies associated with cash constraints (4 days). Throughout 2023, management focused on identifying safety and mechanical process improvements to optimize plant operations, particularly given increasing extreme weather impacts.

Refinery Operations Gross Profit. Refining operations gross profit totaled $37.7 million for 2023 compared to refinery operations gross profit of $41.2 million in 2022, representing a $3.5 million, or 8.5%, decrease. The decrease in 2023 related to lower refining margins and decreased throughput and product demand.

Refining Gross Profit per Bbl. On a per bbl basis, refinery operations gross profit was $9.13 for 2023 compared to gross profit of $9.68 for 2022, representing a decrease of $0.55 per bbl. The decrease related to less favorable commodity prices and decreased refined product demand.

Midstream Operations. Our tolling and terminaling business segment is owned by LRM and NPS. Assets within this segment include petroleum storage tanks and loading and unloading facilities. Tolling and terminaling revenue is derived from storage tank rental fees, ancillary services fees (such as for in-tank blending), and tolling and reservation fees for use of the naphtha stabilizer.

2023 Versus 2022

Tolling and Terminaling Revenue. Storage tank rental and ancillary services fees totaled $6.0 million in 2023 compared to storage tank rental and ancillary services fees of $4.4 million in 2022. Intercompany processing fees were flat at $2.6 million for both periods. The significant increase in storage tank rental revenue in 2023 was the result of Pilot payments in January under the Pilot Forbearance and Accommodation Agreement and in April and June under the Pilot Forbearance Amendment.

Tolling and Terminaling Gross Profit. Tolling and terminaling gross profit totaled $7.0 million in 2023 compared to tolling and terminaling gross profit of $4.9 million in 2022. The $2.1 million, or 42.9%, increase related to higher tolling and terminaling revenue associated with the aforementioned Pilot payments.

(in thousands)

(1) Fees associated with an intercompany tolling agreement related to naphtha volumes.

Capital Resources and Liquidity

We had $6.1 million and $45.2 million in working capital deficits at December 31, 2023 and December 31, 2022, respectively, representing a $39.1 million improvement. Excluding the current portion of long-term debt, we had $33.3 million and $2.1 million in working capital at December 31, 2023 and December 31, 2022, respectively, representing an improvement of $31.2 million. The significant improvement in working capital over the previous year was due to decreases in the current portion of long-term debt, accounts payable, and accrued interest payable. The improvement was also due to a significant increase in cash from operations, accounts receivable, and inventory.

Cash and cash equivalents totaled $18.7 million and $0.5 million at December 31, 2023 and December 31, 2022, respectively, representing an increase of $18.2 million. Restricted cash, noncurrent totaled $0.0 and $1.0 million at December 31, 2023 and December 31, 2022, respectively, and related to a Veritex payment reserve account. The Veritex payment reserve account, which is required to have a balance of $1.0 million, was replenished in early January 2024. Accounts receivable, related party, which was associated with the sale of jet fuel to LEH, totaled $4.2 million and $0.0 at December 31, 2023 and December 31, 2022, respectively.

We generally rely on revenue from operations, including sales of refined products and rental of petroleum storage tanks, Affiliates, and financing to meet our liquidity needs. Our short-term working capital needs are primarily related to: (i) purchasing crude oil and condensate to operate the Nixon refinery, (ii) reimbursing LEH for direct operating expenses and paying the LEH operating fee under the Third Amended and Restated Operating Agreement, (iii) servicing debt, (iv) maintaining and improving the Nixon facility through capital expenditures, and (v) meeting regulatory compliance requirements. Our long-term working capital needs are primarily related to repayment of long-term debt obligations.

We continue to actively explore additional funding to refinance and restructure debt and further improve working capital. During 2023, we entered into the Veritex First Amended Forbearance Agreement, Veritex Second Amended Forbearance Agreement, Kissick Forbearance Agreement, and LEH Forbearance Agreement. During 2022, we secured $1.5 million in working capital through CARES Act loans and entered into the initial forbearance agreement with Veritex. However, there can be no assurance that we will be able to raise additional capital on acceptable terms, or at all.

Refining margins, which are affected by commodity prices and refined product demand, are volatile, and a reduction in refining margins will adversely affect the amount of cash we will have available for working capital. Similarly, capital, credit, and commodity markets, as well as armed conflicts in the Middle East and Europe continue to evolve, and the extent to which these factors may impact our working capital, commodity prices, refined product demand, supply chain, financial condition, liquidity, results of operations, and prospects will depend on future developments, which cannot be predicted with any degree of confidence. In the long term, we may not be able to manage business disruptions or execute our business strategy. We may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing operating.

Sources and Use of Cash

Components of Cash Flows.

(in thousands)

Cash Flow from Operations. We had cash flow from operations of $20.0 million for 2023 compared to cash flow from operations of $16.3 million for 2022, representing a $3.7 million improvement in cash flow from operations between the periods was due to profit from operations, which was offset by a buildup in inventory in 2023 and 2022.

Capital Expenditures. Capital expenditures totaled $0.1 million in both 2023 and 2022. Due to continued uncertainties surrounding general macroeconomic conditions related to inflation, interest rates, and capital and credit markets, geopolitical tensions, including military conflicts in Ukraine and Israel and escalations in the Middle East, and COVID-19, we anticipate continuing to limit capital expenditures over the next twelve months. However, to the extent we can capitalize on green energy growth opportunities, we may finance capital expenditures through project-based government loans.

We account for our capital expenditures in accordance with GAAP. We also classify capital expenditures as ‘maintenance’ if the expenditure maintains capacity or throughput or as ‘expansion’ if the expenditure increases capacity or throughput capabilities. Although classification is generally a straightforward process, in certain circumstances the determination is a matter of management judgment and discretion. We budget for maintenance capital expenditures throughout the year on a project-by-project basis. Projects are determined based on maintaining safe and efficient operations, meeting customer needs, complying with operating policies and applicable law, and producing economic benefits, such as increasing efficiency and/or lowering future expenses.

Debt and Lease Obligations

Debt Agreements.

Related-Party Agreements Summary. Blue Dolphin was a party to the June LEH Note with LEH at December 31, 2022. BDPL was a party to the BDPL-LEH Loan Agreement with LEH at December 31, 2023 and 2022. Summaries of the debt agreements follow:

Pursuant to the Assignment Agreement, the March Ingleside Note and March Carroll Note were assigned to and assumed by LEH under the June LEH Note effective December 31, 2022. Pursuant to a payoff letter dated March 31, 2023, Blue Dolphin fully satisfied the debt and defaults associated with the June LEH Note; as a result, debt and defaults under the March Ingleside Note and March Carroll Note that were assigned to LEH effective December 31, 2022 were also satisfied. All encumbrances that the lender or assignee had against Blue Dolphin were thereby terminated.

Third-Party Agreements Summary. Blue Dolphin and certain subsidiaries are parties to the following debt agreements with third parties:

(in millions)

(in millions)

(1) Restricted cash, noncurrent totaled $0.0 and $1.0 million at December 31, 2023 and December 31, 2022, respectively. Restricted cash, noncurrent reflects amounts held by Veritex in a payment reserve account, which is required to have a balance of $1.0 million. The payment reserve account was replenished in early January 2024.

(2) Original principal amount was $8.0 million; pursuant to a 2017 sixth amendment, principal under the Kissick Debt increased by $3.7 million.

(3) Loan requires monthly interest-only payments for the first thirty-six (36) months. Afterwards, principal and interest payments are due monthly through loan maturity. First payment due in November 2024. As of December 31, 2023 and the filing date of this report, the NPS Term Loan Due 2031 was in default due to covenant violations.

(4) Original principal amount was $0.5 million; the Blue Dolphin Term Loan Due 2051 was modified to increase the principal amount by $1.5 million. Payments deferred for thirty (30) months; first payment due and paid in November 2023; interest accrues during deferral period; loan not forgivable.

(5) Payments deferred for thirty (30) months; first payment made in February 2023; interest accrued during deferral period; loan not forgivable.

(6) In May 2019, LE entered into 12-month equipment rental agreement with an option to purchase backhoe at maturity; equipment rental agreement matured in May 2020; in October 2020, LE entered into the Equipment Loan Due 2025 to finance the backhoe purchase; backhoe used at the Nixon facility.

Guarantees and Security.

(1) Jonathan Carroll was required to personally guarantee repayment of borrowed funds and accrued interest.

(2) Subject to the Kissick Subordination Agreement.

Lease Agreements.

Office Lease. We maintain our corporate headquarters in Houston, Texas. In May 2023, BDSC signed a 12-month extension to its existing operating lease. The extended term commenced on September 1, 2023 and expires on August 31, 2024. Under the amended agreement, the annual rent was reduced from $31.00 per square foot to $30.00 per square foot, resulting in a monthly base rental amount of $0.02 million.

An Affiliate, LEH, subleases a portion of the Houston office space. BDSC received sublease income from LEH totaling $0.03 million for both 2023 and 2022.

Tank Lease. LE leases tanks from Ingleside under the LE Amended and Restated Master Services Agreement. Lease expense associated with the LE Amended and Restated Master Services Agreement totaled $1.2 million and $0 for 2023 and 2022, respectively Due to its one-year term, the lease is being treated as short-term.

Outstanding Principal, Debt Issue Costs, and Accrued Interest. Related and third-party long-term debt, including outstanding principal and accrued interest, as of the dates indicated was as follows:

Outstanding Principal and Accrued Interest.

(in thousands)

The debt associated with the LE Term Loan Due 2034, LRM Term Loan Due 2034, NPS Term Loan Due 2031, and Kissick Debt was classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2023 and 2022. Although the debt associated with the BDPL-LEH Loan Agreement was classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 2022, the debt was reclassified to long-term debt, net of current portion at December 31, 2023 as a result of the LEH Forbearance Agreement.

Debt Issue Costs. Unamortized debt issue costs associated with the Veritex and GNCU loans as of the dates indicated consisted of the following:

(in thousands)

Amortization expense was $0.2 million for both 2023 and 2022.

Accrued Interest. Related-party and third-party accrued interest payable associated with long-term debt in our consolidated balance sheets, as of the dates indicated consisted of the following:

(in thousands)

Forbearance Agreements and Default.

Kissick Forbearance Agreement. Pursuant to the Kissick Forbearance Agreement, Kissick Noteholder agreed to forbear from exercising any of its rights and remedies related to existing defaults pertaining to payment violations under the Kissick Debt. Under the terms of the Kissick Forbearance Agreement, LE agreed to make monthly principal and interest payments totaling $0.5 million beginning in April 2023, continuing on the first of each month through February 2025, with a final payment of $0.4 million to Kissick Noteholder on March 1, 2025. LE paid Kissick Noteholder $4.5 million in 2023. As of the filing date of this report, the Kissick Debt was in forbearance related to past defaults prior to April 2023.

LEH Forbearance Agreement. Pursuant to the LEH Forbearance Agreement, LEH agreed to forbear from exercising any of its rights and remedies related to existing defaults pertaining to payment violations under the BDPL-LEH Loan Agreement. Under the terms of the LEH Forbearance Agreement, BDPL agreed to make interest-only monthly payments approximating $0.05 million beginning in May 2023, continuing on the fifteenth of each month through April 2025. Beginning in May 2025, BDPL agreed to make principal and interest monthly payments approximating $0.4 million through April 2027. Interest will be incurred throughout the agreement, including the interest-only payment period. BDPL paid LEH approximately$3.4 millionin 2023. As of the filing date of this report, the BDPL-LEH Loan Agreement was in forbearance related to past defaults prior to May 2023.

Defaults. As of December 31, 2023 and the filing date of this report, we were in default under the NPS Term Loan Due 2031 due to covenant violations. At December 31, 2023 and through March 29, 2024, we were in forbearance under the LE Term Loan Due 2034 and LRM Term Loan Due 2034; as of the filing date of this report, we were in default under the LE Term Loan Due 2034 and LRM Term Loan Due 2034 due to covenant violations. Defaults may permit lenders to declare the amounts owed under the related loan agreements immediately due and payable, exercise their rights with respect to collateral securing obligors’ obligations, and/or exercise any other rights and remedies available.

We can provide no assurance that: (i) our assets or cash flow will be sufficient to fully repay borrowings under secured loan agreements that are in default, either upon maturity or if accelerated, (ii) LE, LRM, NPS, or BDPL will be able to refinance or restructure the debt, and/or (iii) third parties will provide future forbearances or default waivers, particularly if the banks with whom we have relationships fail. If one or more banks fail, we could be exposed to additional events of default (if not cured or waived) under existing secured loan agreements. Defaults under our secured loan agreements and any exercise by third parties of their rights and remedies related to such defaults may have a material adverse effect on our business, the trading price of our Common Stock, and on the value of an investment in our Common Stock, and holders of our Common Stock could lose their investment in our Common Stock in its entirety. If the debt associated with secured loan agreements is accelerated and we are unable to refinance or restructure the debt or obtain default waivers, we may have to consider other options, including selling assets, raising additional debt or equity capital, cutting costs, reducing cash requirements, filing bankruptcy, or ceasing operating.

Proceeds from Debt. Net proceeds from the issuance of debt totaled $0.0 for 2023 and $1.5 million for 2022. Proceeds in 2022 represented additional principal under the Blue Dolphin Term Loan Due 2051.

Total Debt and Lease Obligations by Settlement. The table below summarizes our principal contractual debt and lease obligations at December 31, 2023, by expected settlement period:

(in thousands)

(1) See “Part II, Item 8. Financial Statements and Supplementary Data – Notes (3) and (10)” for additional disclosures related to third-party and related-party debt.

(2) Excludes interest payable; at December 31, 2023, interest payable and interest payable, related party was estimated to be $2.6 million (less than 1 year), $1.3 million (between 1 and 3 years), $0 (between 3 and 5 years), and $0 (5 years and later).

See “Part II, Item 8. Financial Statements and Supplementary Data – Notes (3) and (15)” for additional disclosures related to Affiliate agreements and arrangements for additional disclosures related to Affiliate risk.

Concentration of Customers Risk

We routinely assess the financial strength of our customers. To date, we have not experienced significant write-downs in accounts receivable balances. We believe that our accounts receivable credit risk exposure is limited.

One of our significant customers is LEH, an Affiliate. LEH purchases our jet fuel under an Amended and Restated Jet Fuel Sales Agreement and sells the jet fuel to the DLA under preferential pricing terms due to its HUBZone certification LEH lifts the jet fuel stored at the Nixon Facility as needed. For 2023 and 2022, the Affiliate accounted for approximately 31.7% and 35.7% of total revenue from operations, respectively. The Affiliate represented approximately $4.2 million and $0.0 in accounts receivable, related party at December 31, 2023 and 2022, respectively.

Surety Bonds

BOEM Supplemental Pipeline Bonds. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the statutory bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning pipelines and platforms at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM.

Historically, BDPL maintained $0.9 million in pipeline bonds with BOEM to decommission its trunk pipeline offshore in federal waters. In March 2018, BOEM ordered BDPL to provide additional financial assurance totaling approximately $4.8 million for five (5) existing pipeline rights-of-way, an increase of approximately $3.9 million. In June 2018, BOEM issued BDPL INCs for each right-of-way that failed to comply. BDPL appealed the INCs to the IBLA. Although the IBLA granted multiple extension requests, the Office of the Solicitor of the U.S. Department of the Interior indicated that BOEM would not consent to further extensions. The solicitor’s office signaled that BDPL’s adherence to decommissioning its offshore pipelines and platform would likely help in future discussions with BOEM related to the INCs. Fulfilling abandonment obligations related to the subject assets will significantly reduce or eliminate the amount of supplemental pipeline bonds required by BOEM, which may serve to partially or fully resolve the INCs.

BDPL’s pending appeal of the BOEM INCs does not relieve BDPL of its obligations to provide additional financial assurance or of BOEM’s authority to impose financial penalties. There can be no assurance that we will be able to meet additional supplemental pipeline bond requirements. If BDPL is required by BOEM to provide significant additional supplemental pipeline bonds or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. We cannot predict the outcome of the supplemental pipeline bond INCs. Accordingly, we did not record a liability on our consolidated balance sheets as of December 31, 2023 and 2022. At both December 31, 2023 and 2022, BDPL maintained approximately $0.9 million in pipeline rights-of-way surety bonds issued to BOEM through RLI Corp. ("RLI"). However, as noted below, RLI desires to reduce its risk profile related to BDPL's bonds. Of the pipeline rights-of-way bonds, $0.7 million was credit-backed and $0.2 million was cash-backed.

RLI Surety Bonds. Blue Dolphin currently has several surety bonds through RLI as required by different regulatory agencies, including BOEM and the Railroad Commission of Texas. The bonds total approximately $1.25 million in the aggregate, of which $0.2 million is collateralized in cash. In June, July, and December 2023, RLI demanded Blue Dolphin provide additional cash collateral or a letter of credit totaling approximately $1.0 million or provide bond exonerations and replacement bonds. Although Blue Dolphin received a proposal from another surety to replace the RLI bonds at a 50% collateral requirement, management was hopeful Blue Dolphin and RLI could reach an understanding whereby the existing bonds could be maintained until BDPL completed decommissioning of the subject assets. Abandonment of BDPL’s offshore pipeline and platform assets will eliminate the need for all BOEM supplemental pipeline bonds, reducing the amount of surety bonds held by RLI from $1.25 million to $0.25 million. On February 19, 2024, RLI filed suit against Blue Dolphin, BDPL, and BDEX seeking an injunction for the payment of approximately $1.0 million of additional collateral for the bonds.

BSEE Offshore Platform Inspections and Decommissioning Obligations

BDPL has pipelines and platform assets subject to BSEE’s idle iron regulations. Idle iron regulations require lessees and rights-of-way holders to permanently abandon and/or remove platforms and other structures when they are no longer useful for operations. Until such structures are abandoned or removed, lessees and rights-of-way holders are required to inspect and maintain the assets in accordance with regulatory requirements.

Platform Inspections. We are required by BSEE to perform annual structural inspections of our offshore platform, as well as to perform monthly platform checks of navigational aids, fog horns, and lifesaving equipment. In March 2023, BSEE issued BDPL an INC for failing to perform the required 2021 and 2022 structural surveys for the GA-288C platform and for failing to provide BSEE with such survey results. In April 2023, BSEE granted BDPL an extension for completing the required platform inspection until May 30, 2023. Although BDPL requested a second extension, BSEE denied BDPL’s request. BDPL completed the platform inspection on August 26, 2023 and submitted the survey report to BSEE on September 6, 2023. Because BDPL failed to comply with the INC within the allotted timeframe, BSEE proposed an administrative civil penalty of approximately $0.2 million on October 24, 2023. The proposed administrative civil penalty was finalized on January 26, 2024, for $0.2 million. We recorded a liability for the maximum proposed amount of $0.2 million on our consolidated balance sheets within accrued expenses and other current liabilities as of December 31, 2023. BDPL filed an appeal to the civil penalty on March 25, 2024.

Decommissioning Obligations. Because our pipelines and facilities assets have been inactive for an extended period, BOEM mandated that they be decommissioned. In October 2023, management met BSEE to discuss BDPL’s path forward for meeting decommissioning requirements. Management worked with a consultant to develop a decommissioning plan, and BDPL submitted its decommissioning plan to the agency in November 2023. Although the decommissioning of these assets was delayed due to cash constraints associated with historical net losses and the impact of COVID-19, a significant portion of the decommissioning project was completed from late December 2023 to mid-February 2024. Additional work is planned for the second quarter of 2024. Based on resource availability and projected weather conditions, we believe decommissioning and remediation of all associated INCs will be completed by the end of the second quarter 2024. However, BDPL’s work plan does not relieve BDPL of its obligations to comply with BSEE’s mandate or BSEE’s authority to impose financial penalties. Further, there can be no assurance that BDPL can complete anticipated work or predict the outcome of BSEE INCs. Accordingly, we did not record a liability related to potential penalties on our consolidated balance sheets as of December 31, 2023 and 2022. Due to BDPL’s failure to comply with BSEE requirements, BDPL could still be subject to regulatory oversight and enforcement, including but not limited to failing to correct an INC, civil penalties, and revocation of BDPL’s operator designation, which could have a material adverse effect on our earnings, cash flows, and liquidity. On December 31, 2023 and 2022, BDPL maintained $4.5 million and $3.7 million, respectively, in AROs related to the abandonment of these assets, which amount does not include potential penalties.

Off-Balance Sheet Arrangements

None.

Accounting Standards

Critical Accounting Policies and Estimates.

Significant Accounting Policies. Our significant accounting policies relate to use of estimates, cash and cash equivalents, restricted cash, accounts receivable and allowance for credit losses, inventory, property and equipment, leases, revenue recognition, income taxes, impairment or disposal of long-lived assets, asset retirement obligations, and computation of earnings per share.

Estimates. The nature of our business requires that we make estimates and assumptions in accordance with U.S. GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenue and expenses during the reporting period. Although commodity price volatility, recession and inflation, armed conflicts in the Middle East and Europe and associated sanctions on Russian crude products, and severe weather resulting from climate change have impacted these estimates and assumptions, we are continually working to mitigate future risks. However, the extent to which these factors may impact our business, financial condition, liquidity, results of operations, and prospects will depend on future developments, which cannot be predicted with any degree of certainty.

We assessed certain accounting matters that require consideration of forecasted financial information in context with information reasonably available to us as of December 31, 2023 and through the filing date of this report. The accounting matters assessed included, but not limited to, our allowance for credit losses, inventory, and related reserves, and the carrying value of long-lived assets.

New Pronouncements Adopted. During 2023 and 2022 we did not adopt any ASUs.

New Pronouncements Issued, Not Yet Effective. No new pronouncements that have been issued but are not yet effective are expected to have a material impact on our financial position, results of operations, or liquidity.

• ASU 2023-09 — Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"). In December 2023, the FASB issued ASU 2023-09, requiring us to disclose specified additional information in its income tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. ASU 2023-09 will also require us to disaggregate our income taxes paid disclosure by federal and state taxes, with further disaggregation required for significant individual jurisdictions. We will adopt ASU 2023-09 in the fourth quarter of 2026. ASU 2023-09 allows for adoption using either a prospective or retrospective transition method.
• ASU 2023-07 — Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (ASU 2023-07). In November 2023, the FASB issued ASU No. 2023-07, requiring us to disclose significant segment expenses regularly provided to our chief operating decision maker (“CODM”). In addition, ASU 2023-07 will require us to disclose the title and position of our CODM and how the CODM uses segment profit or loss information in assessing segment performance and deciding how to allocate resources. We will adopt ASU 2023-07 in our fourth quarter of 2025 using a retrospective transition method.

Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our Chief Executive Officer (principal executive officer, principal financial officer, and principal accounting officer) to allow timely decisions regarding required disclosure. Under the supervision of, and with the participation of our management, including our Chief Executive Officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this report. Based on our evaluation, our Chief Executive Officer (principal executive officer, principal financial officer, and principal accounting officer) concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act, are recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms.

Management’s Report on Internal Control over Financial Reporting

Management’s Responsibility. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the U.S.

There are inherent limitations in the effectiveness of any control system, including the potential for human error and the possible circumvention or overriding of controls and procedures. Additionally, judgments in decision-making can be faulty and breakdowns can occur because of a simple error or mistake. An effective control system can provide only reasonable, not absolute, assurance that the control objectives of the system are adequately met. Accordingly, management does not expect that the control system can prevent or detect all errors or fraud. Further, projections of any evaluation or assessment of effectiveness of a control system to future periods are subject to the risks that, over time, controls may become inadequate because of changes in an entity’s operating environment or deterioration in the degree of compliance with policies or procedures.

Management’s Assessment. Management, under the supervision and with the participation of our Chief Executive Officer (principal executive officer, principal financial officer, and principal accounting officer), assessed the effectiveness of our internal controls over financial reporting at December 31, 2023. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations of the Treadway Commission Framework and SOX Compliance. Management determined that our internal controls over financial reporting were effective for the twelve months ended December 31, 2023.

Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Exemption from Management's Report on Internal Control over Financial Reporting. This report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the SEC for smaller reporting companies that permit us to provide only management’s attestation in this report.