Glossary of Terms

Throughout this Annual Report on Form 10-K, we have used the following terms:

Important Information Regarding Forward-Looking Statements

This report (including information incorporated by reference) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act, including, but not limited to, those under “Part I, Item 1. Business” and “Part I, Item 1A. Risk Factors,” as well as “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All statements other than statements of historical fact, including without limitation statements regarding expectations regarding revenue, cash flows, capital expenditures, and other financial items, our business strategy, goals, and expectations concerning our market position, future operations, and profitability, are forward-looking statements. Forward-looking statements may be identified by use of the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will,” “would” and similar terms and phrases. Although we believe our assumptions concerning future events are reasonable, several risks, uncertainties, and other factors could cause actual results and trends to differ materially from those projected, including but not limited to:

See also the risk factors described in greater detail under “Part I, Item 1A. Risk Factors” of this report.  All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to revise or update any forward-looking statements as a result of new information, future events, or otherwise.

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

Part I should be read in conjunction with “Part II, Item 7. Management’s Discussion and Analysis and Results of Operations” and “Part II, Item 8. Financial Statements and Supplementary Data”.

PART I

ITEM 1.         BUSINESS

The following section of this Annual Report on Form 10-K generally refers to business developments during the twelve months ended December 31, 2024. 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, 2023.

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.”

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 83.7% 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.  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.

Our Operations

Our assets are organized into two business segments:

‘Corporate and other’ includes Blue Dolphin subsidiaries BDPL (inactive pipeline and facilities assets), BDPC (inactive leasehold interests in offshore oil and gas wells), and BDSC (administrative services).  For more information related to our business segments, see “—Downstream Operations, —Midstream Operations, and — Inactive Operations” and “Part I. Item 2. Properties” in this report.

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 2023, we operated under the Tartan Crude Supply Agreement.  Tartan also 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.  During 2023, the vast majority of our crude was sourced from Tartan under the Tartan Crude Supply Agreement.  

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 the crude supply agreement renews on a quarterly evergreen basis.  Related to the crude supply agreement, MVP stores crude oil at the Nixon facility under a terminal services agreement. Management believes that MVP can provide us with adequate amounts of crude oil and condensate for the foreseeable future.  Because we 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.  If we are unable to manage this, we may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing 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 naphtha and HOBM 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, LEH, purchases most of our jet fuel under the Amended and Restated Jet Fuel Sales Agreement; LEH then sells the jet fuel to the DLA under preferential pricing terms due to the Affiliate's HUBZone certification.  The agreement with LEH has a one-year term with automatic renewals.  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). An Affiliate, LEH, is a significant customer.  Most of our contracts require our customers to prepay, with us selling them fixed quantities 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 periodically complete a planned turnaround to repair, restore, refurbish, or replace refinery equipment. 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.  Common reasons for unplanned downtime include repair/replacement of disabled equipment, crude deficiencies associated with cash constraints, extreme temperatures (high or low), and power outages.

We are particularly vulnerable to operational disruptions because all our refining operations occur at a single facility. Shutdowns for maintenance may result in lost margin opportunity, potential increased maintenance expense, and reduced refined products inventory, which could adversely impact 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.

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 pipeline and facilities assets and have leasehold interests in offshore oil and gas properties.  These assets are inactive.  Our pipeline assets were fully impaired in 2016 and our leasehold interests in offshore oil and gas wells were fully impaired in 2011. Our pipeline assets and oil and gas leasehold interests had no revenue during the years ended December 31, 2024 and 2023. 

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.

Operating Risks

Working Capital. We have historically had working capital deficits primarily due to having significant debt in current liabilities, certain of which was in default. 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 managing capital expenditures.

As of December 31, 2024 and the filing date of this report, certain conditions and events existed, in the aggregate, that caused management to evaluate Blue Dolphin's ability to continue as a going concern.  Those conditions and events included historical working capital deficits and significant debt in current liabilities, certain of which was in default. 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).  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.

We had a working capital deficit of $19.1 million at December 31, 2024 compared to a working capital deficit of $6.1 million at December 31, 2023, representing a $13.0 million decrease. Our significant debt in current liabilities at December 31, 2024 consisted of bank debt to Veritex and GNCU and related-party debt. Excluding accrued interest, we had current related-party and third-party debt of $40.6 million and $39.4 million as of December 31, 2024 and 2023, respectively.  The $1.2 million increase in current debt between the periods primarily related to a $3.3 million draw under the Affiliate Revolving Credit Agreement offset by loan payments. We continue to engage with potential lenders to obtain additional funding to refinance and restructure debt and further improve working capital.

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. Therefore, the effect of crude oil commodity price changes on our finished petroleum product commodity prices 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 and our product slate based on market conditions, including commodity price and refined product demand.

Nixon Refinery Operations. 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, tariffs, interest rates, capital and credit markets, and geopolitical tensions (including military conflicts in Ukraine and Israel and escalations in the Middle East), 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.

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 and Freeport 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 that any 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 for losses 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.,” an inactive wholly owned subsidiary, is a registered trademark in the U.S. in name form. In addition, “www.blue-dolphin-energy.com” is a registered domain name.

Human Capital Management

General. Our operations and activities are managed by an Affiliate, LEH, under the Third Amended and Restated Operating Agreement. Blue Dolphin and its subsidiaries do not have any employees.  As of December 31, 2024,112 employees of the Affiliate provided support for our operations. None of these employees were covered by collective bargaining agreements. We believe that our personnel provide a competitive advantage for our success.  We strive to attract and retain highly qualified and motivated individuals, foster a culture that supports diversity and inclusion, and 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. We use eCompliance, a mobile software solution that increases frontline adoption of health and safety policies and reduces on-site risks. Although we strive 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.

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 of 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, Freeport 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 under the Petroleum Refinery National Initiative 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 were 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.  As a result of our 2014 product slate change, our refined products no longer fall under RFS or RFS2 requirements.

Currently, multiple legislative and regulatory measures to address GHG 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 GHG 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 GHG 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 included 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.  In January 2025, President Trump signed an executive order directing the U.S. to withdraw from the Paris Agreement, and it is expected that President Trump and the Republican-led Congress will diverge from the previous administration’s positions and GHG commitments. However, future emission reduction targets and other provisions of legislative or regulatory initiatives and policies enacted in the future by the U.S. could be brought by future administrations or, in the absence of federal action, states may become more active and focused on taking legislative or regulatory actions aimed at climate change and minimizing GHG emissions.

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 were 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 current 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, first Trump, and Biden Administrations have pursued multiple rulemakings 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 the U.S. Supreme Court's decision 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 oil spill response organizations available to respond to an oil spill and, in the case of our offshore pipelines, we maintain the required statutory coverage of financial responsibility at $35.0 million. In the event of an oil spill into navigable waters, we could 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 requested public comment on the proposed regulation, and the public comment period ended in May 2023.  In April 2024, the EPA announced the final PFAS National Primary Drinking Water Regulation for six (6) PFAS in public water systems.  A number of states have also issued their own drinking water, surface water, and groundwater limits for various PFAS. We cannot currently predict the impact of PFAS-related regulations will have on our compliance or remediation costs.

Offshore Decommissioning Requirement.  In April 2023, BSEE updated its guidance and regulations on decommissioning that mandates lessees and rights-of-way holders to permanently abandon and remove platform and other structures within one year of expiration of a lease or right-of-way grant or when no longer useful for operations.  To cover various obligations of lessees and rights-of-way holders operating in federal waters of the U.S. Gulf of America, BOEM evaluates an operator's financial ability to carry out present and future work obligations to determine whether the operator must provide additional security beyond 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.  In April 2024, the U.S. Department of the Interior announced BOEM's final rule titled, "Risk Management and Financial Assurance for OCS Lease and Grant Obligations." BOEM's final rule became effective in June 2024. However, pursuant to an order issued in early 2025 by the Secretary of the U.S. Department of the Interior implementing Trump Administration Executive Order 14154 “Unleashing American Energy,” BOEM’s final rule is to be suspended, revised, or rescinded. 

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 expiration of a lease or right-of-way or after a certain period of inactivity. respectively. At both December 31, 2024 and 2023, BDPL maintained $0.9 million in cash-backed pipeline bonds issued to the BOEM through RLI Corp. BDPL maintained $3.0 million and $4.5 million in AROs related to decommissioning its pipeline and facilities assets at December 31, 2024 and 2023, respectively. See “Part I, Item 1A. Risk Factors—Legal, Government, and Regulatory (Section C)" and "Part II, Item 8. Financial Statements and Supplementary Data—Notes (15) and (16)" 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.  

ITEM 1A.  RISK FACTORS

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. These risk factors do not identify all risks that we face; our operations could also be affected by factors, events, or uncertainties that are not presently known to us or that we do not currently consider to present significant risks to our operations.

Excluding accrued interest, we had current related-party and third-party debt of $40.6 million and $39.4 million as of December 31, 2024 and 2023, respectively. Our significant debt in current liabilities, certain of which was in default at December 31, 2024, consisted of bank debt to Veritex and GNCU and related-party debt.  We classified the debt associated with the LE Term Loan Due 2034, LRM Term Loan Due 2034, and NPS Term Loan Due 2031 within long-term debt, current portion on our consolidated balance sheets at December 31, 2024 and 2023 due to being in default.

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.

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, 2024 and through the filing date of this report, NPS was in default related to non-financial covenants under the NPS Term Loan Due 2031. LE and LRM were in default related to financial covenants under the LE Term Loan Due 2034 and LRM Term Loan Due 2034, respectively. Defaults may permit lenders to declare amounts owed under the related loan agreement immediately due and payable, exercise their rights with respect to collateral securing obligors’ obligations, and 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 the secured loan agreements that are in default, either upon maturity or if accelerated, (ii) NPS, LE, or LRM will be able to refinance or restructure the debt, or (iii) the lender will provide a future forbearance or default waiver. Any exercise by the lender of their rights and remedies under the secured loan agreements that are in default could have a material adverse effect on our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations.  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.  If we are unable to manage this, we may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing operations.

Our ability to meet financial and non-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. Our ability to generate sustained positive margins depends on, among other things, business conditions and the general condition of the financial markets. Uncertainties surrounding general macroeconomic conditions related to inflation, tariffs, interest rates, capital and credit markets, and geopolitical tensions (including military conflicts in Ukraine and Israel and escalations in the Middle East) may adversely impact our working capital, commodity prices, refined product demand, and our supply chain, which would impact our ability to 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 and non-financial covenants could intensify.

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 pandemics, 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 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.

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.

We have an indirect controlling stockholder. As a related party of an Affiliate, Jonathan Carroll indirectly owned 83.7% 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:

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 from and sell products to 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.

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 offshore 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.

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 U.S. Gulf of America. 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.

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.

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.

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% stockholders, 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, 2024, 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 recorded no valuation allowances against our deferred tax assets as of December 31, 2024.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using innovative technologies. As others use or develop innovative technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those innovative technologies at substantial costs. We may not be able to respond to these competitive pressures or implement recent 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.

Borrowings under certain of our secured loan agreements with third parties are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness will increase even though the amount borrowed remains the same, and our net income and cash flows, including cash available for servicing our indebtedness, would correspondingly decrease. As of  December 31, 2024, approximately $29.8 million of our debt was variable rate debt. Our anticipated annual interest expense on $29.8 million of variable rate debt at the current rate of 10.25% would be $3.1 million.

Our financial results are affected by the relationship, or margin, between our refined product prices and the price for crude oil, which can vary based on global, regional, and local market conditions. Historically, refining margins have been volatile, and we believe they will continue to be volatile in the future. Our cost to acquire feedstocks and the price at which we can ultimately sell products depend upon several factors beyond our control, including regional and global supplies of and demand for feedstocks (such as crude oil), liquid transportation fuels, and other products. These in turn depend on, among other things, the availability and quantity of feedstocks and liquid transportation fuels imported into the U.S., the production levels of suppliers, levels of product inventories, productivity and growth (or the lack thereof) of the U.S. and global economies, the U.S. government’s relationships with foreign governments, political affairs, the extent of government regulation, including tariffs, and the events described in many of the other risk factors below. The ability of the members of the OPEC to agree on and to maintain crude oil price and production controls has also had, and is likely to continue to have, a significant impact on the market prices of crude oil and certain of our products.

Some of these factors can vary by region and may change quickly, adding to market volatility, while others may have longer-term effects. The longer-term effects of these and other factors on refining margins are uncertain. We do not produce crude oil, and we must purchase nearly all of the feedstock we process. Price level changes during the period between purchasing crude oil and selling the resulting refined products has had, and could continue to have, a significant effect on our financial results. A decline in market prices for our refined products and crude oil has had, and could again have, a negative impact to the carrying value of our inventories. Factors outside of our control, such as economic uncertainty, inflation (and the potential for increased prices to create demand destruction), tariffs, persistently high interest rates, public health crises, and political unrest or hostilities, have affected, and could continue to affect, economic activity and growth levels of the U.S. and other countries. A decrease in the demand for and consumption of our products due to lower economic activity and growth levels has caused, and could again cause, declines in our revenues and refining margins and could negatively impact our growth prospects and capital allocation decisions.

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. For example, if the price per barrel of crude oil decreases, the price of jet fuel per barrel will also generally decreases, as jet fuel is a refined product derived from crude oil.  Therefore, the effect of crude oil commodity price changes on our finished petroleum product commodity prices 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:

Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate on favorable terms. During 2023, we operated under the Tartan Crude Supply Agreement. 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.  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, volume delivered under the Tartan Crude Supply Agreement, as a percentage of the total net bbls of crude oil deliverable, was 71.0%. During the twelve months ended December 31, 2023, substantially all our crude was sourced from Tartan.  

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 the crude supply agreement renews on a quarterly evergreen basis.  Related to the crude supply agreement, MVP stores crude oil at the Nixon facility under a terminal services agreement. Management believes that MVP can provide us with adequate amounts of crude oil and condensate for the foreseeable future.  Because we 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.  If we are unable to manage this, we may have to consider other options, such as selling assets, raising additional debt or equity capital, filing bankruptcy, or ceasing 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, 2024 and 2023, the refinery experienced no 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.

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, extreme 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.

Our operations depend on the reliable supply of electricity. We consume significant amounts of electricity to operate the Nixon facility, and electricity price has a measurable effect on the total cost of our operations. Additionally, the availability and cost of electricity has been, and could continue to be, affected by numerous events, such as government regulations, weather (e.g., hurricanes and periods of considerable heat or cold, such as Winter Storm Uri in 2021), logistics interruptions, electric grid outages, cybersecurity incidents, intermittent electricity generation (particularly from wind and solar), hostilities, sanctions, human error, and supply and demand imbalances for electricity. For example, the real-time market structure of the primary grid provider in Texas exposes the Nixon facility and our other locations in Texas to “scarcity pricing” during periods of supply and demand imbalance. As electrification continues to grow, or if there are increased restrictions or costs imposed on the ability of utilities or power suppliers to utilize certain energy sources (such as through restrictions on fossil fuel or nuclear-generated electricity or environmental, social, and governance pressure not to use such sources of electricity generation), there will likely be increased strains on and risks to the integrity, reliability, and resilience of electrical grids, and increased volatility and tightness in electricity supplies across the world. These events could negatively affect the cost, reliability, and availability of our electricity supply and may cause sporadic outages that disrupt our operations. Growing electrification and rapidly developing and increasing technology use (such as artificial intelligence, computer processing, cryptocurrency mining, and cloud storage, and the data centers and power supplies required to support these activities) will also likely increase the intermittency and decrease the reliability of electricity supplies, particularly for grids highly dependent upon wind and solar power, which would exacerbate the foregoing challenges. Additionally, increased government regulations and public opposition to pipeline construction and electricity generation and transmission projects have resulted in, and could continue to result in, the underinvestment in, or unavailability of, the infrastructure and logistics assets needed to obtain natural gas feedstocks and electricity in a reliable and cost-efficient manner. Increases in prices for electricity, or disruptions to our supply thereof, have in the past, and could again, materially and adversely affect our business, financial condition, results of operations, and liquidity.

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.

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.

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 $0.0 million and $0.9 million at December 31, 2024 and 2023, 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. No amounts for either period related to Affiliate borrowings for working capital.

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, 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.

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 officer; Bryce Klug currently serves as our principal financial and accounting officer; and William Christopher McDougall currently serves as our Corporate Development Officer.  We are highly dependent on their 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.

Most of our contracts require our customers to prepay and for us to sell to our customers fixed quantities 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 we lose a key customer, a key customer reduces their order quantity, or a key customer requires us to reduce our commodity prices.  We may further be harmed if a key customer 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.

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, or our refined products or experience interruptions in transportation because of acts of God, accidents, government regulation, terrorism or other events, our revenue and net income would be materially and adversely affected.

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.

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.

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 severe 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.

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 recent technologies at substantial costs to achieve our strategy. While the Biden Administration advanced significant climate-related initiatives, including incentives to promote renewable energy, recent changes under the Trump Administration following the 2024 U.S. presidential election have begun to, and may further shift, regulatory priorities away from renewable energy. Through executive orders and regulatory rollbacks, certain Biden-era initiatives have been curtailed or reevaluated and incentives to increase fossil fuel production have been promoted, creating a more uncertain regulatory landscape which may materially impact our plans to capture renewable energy opportunities. Throughout 2024, management had meaningful discussions with potential commercial partners. However, 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 or financing of new renewable energy projects and us abandoning the development of renewable energy projects.

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, 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 Nixon facility operates under several federal and state permits, licenses, and approvals with terms and conditions that contain a substantial 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.

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.

In February 2025, the Trump Administration imposed tariffs on imports to the U.S. from Canada, China, and Mexico as part of an emergency response to deemed national threats. While the Trump Administration initially negotiated a temporary stay in implementation of the tariffs against Canada and Mexico, the tariffs went into effect in March 2025.  In response to U.S. tariffs, Canada, China, and Mexico each imposed retaliatory tariffs on certain U.S. goods.  While we obtain our crude oil and condensate from the Eagle Ford Shale (domestically sourced crude), U.S. refiners that have historically sourced heavy crude oil from Canada and Mexico are identifying lighter, domestic crude oil to use as an alternative in their refining processes. The shift in demand for U.S.-sourced crude oil could adversely impact the cost and supply of crude oil and condensate that we acquire from the Eagle Ford Shale, as well as the price for our refined products, which may lower our refining margins and could have a material adverse effect on our financial results and financial condition.

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.

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, the impact of tariffs on goods and services, 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, among many other factors, 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.

BOEM Supplemental Pipeline Bonds. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the U.S. Gulf of America, 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 $5.7 million for five (5) existing pipeline rights-of-way, an increase of approximately $4.8 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, 2024 and 2023.  At both December 31, 2024 and 2023, BDPL maintained $0.9 million in cash-backed pipeline bonds issued to the BOEM through RLI Corp.

RLI Corp. Surety Bonds. Blue Dolphin currently has several surety bonds through RLI Corp. 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 was collateralized in cash. In February 2024, RLI Corp. filed suit against Blue Dolphin, BDPL, and BDEX seeking an injunction for the payment of approximately $1.0 million of additional cash collateral for the bonds. BDPL filed its answer to RLI Corp.'s lawsuit in April 2024 denying RLI Corp.'s claims, and in July 2024 BDPL presented a settlement proposal to RLI Corp. to resolve the matter through a series of payments collateralizing the bonds with cash. In July 2024, RLI Corp. informed the court that the parties reached a settlement in principle, and the parties executed a settlement agreement in September 2024. From September to December 2024, BDPL made payments to RLI Corp. under the settlement agreement totaling $0.6 million. As of the filing date of this report, BDPL was in compliance with the settlement agreement with RLI Corp. Once complete, abandonment of BDPL’s offshore pipeline and platform assets will eliminate the need for all BOEM supplemental pipeline bonds, which would reduce the amount of surety bonds held by RLI Corp. from $1.25 million to $0.25 million.

BSEE Offshore Platform Inspections, Decommissioning Obligations, and Civil Penalties. 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 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 Inspection Obligation. 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. 

Decommissioning Obligations.  Because our pipelines and facilities assets have been inactive for an extended period, BSEE 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 during the pandemic, a sizeable portion of the decommissioning project was completed from late December 2023 to mid-February 2024. Additional work was planned for 2024; however, no additional work was performed due to significant cost overruns under the first phase of work due to poor weather conditions. In July 2024, BDPL requested a BSEE extension to decommission the remaining portion of the Blue Dolphin Pipeline System and associated platform until the second quarter of 2025; BDPL’s request for a decommissioning extension was denied by BSEE in September 2024.  On March 17, 2025, BSEE issued BDPL an INC for failing to comply with certain of its decommissioning obligations; see "Note (16) for additional disclosures related to this BSEE INC.

Management is currently assessing the feasibility and cost of performing decommissioning work. Separately, management is also exploring alternatives to reactivate the assets under a potential alternate Right-of-Use and Easement (RUE).  BDPL's delay in decommissioning its offshore assets does not relieve BDPL of its obligations to comply with BSEE's mandate or of BSEE's authority to impose civil penalties. Further, there can be no assurance that BDPL will be able to complete the anticipated work or predict the outcome of BSEE INCs. If BDPL is unable to perform its decommissioning obligations, BOEM may exercise its rights under supplemental pipeline bonds or exercise any other rights and remedies it has available.

BSEE Civil Penalties. During the twelve months ended December 31, 2024 and 2023 BDPL received the following BSEE civil penalty referral letters:

At December 31, 2024 and 2023, BDPL maintained $3.0 million and $4.5 million, respectively, in AROs related to abandonment of its pipeline and facilities assets.  See "Part II, Item 8—Financial Statements and Supplementary Data -- Notes (11), (15), and (16)" for additional disclosures related to AROs and BSEE civil penalties. 

TCEQ Final 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 believed the penalty matter is resolved in September 2023, TCEQ referred the matter to the State Office of Administrative Hearings ("SOAH"). A preliminary hearing, the purpose of which was to set a hearing schedule, was held on August 8, 2024; management participated in the hearing. Although a follow-up hearing was scheduled for January 2025, TCEQ presented, and LRM signed, a revised draft Agreed Order in November 2024.  Under the terms of the revised draft Agreed Order, TCEQ acknowledged that LRM had ceased unauthorized disposal of industrial solid waste and industrial hazardous waste and LRM accepted a final penalty amount of approximately $0.4 million, which will be paid in monthly installments over a three-year period. The SOAH case was dismissed and the matter was remanded back to the TCEQ December 2024; TCEQ finalized the Agreed Order in February 2025.  At both  December 31, 2024 and 2023, we accrued $0.4 million on our balance sheet within accrued expenses and other current liabilities related to this matter.

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 the seafloor. 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 severe 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.  See Risk Factor C5. within this "Item 1A. Risk Factors" section and "Part II, Item 8—Financial Statements and Supplementary Data -- Notes (11), (15), and (16)" for additional disclosures related to our AROs. 

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. Although our pipelines are inactive, PHMSA regulations require pipelines to be maintained and monitored to ensure safety standards are met until the subject pipeline is officially taken out of service and properly abandoned.  The rules require pipeline operators to:

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.

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 GHGs (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. In recent years, more aggressive efforts by governments and non-governmental organizations to put in place laws requiring or otherwise driving reductions in GHG emissions were gaining approval. 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, GHG cap-and-trade programs or taxes on GHGs, 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.

Although the Biden Administration focused on reducing GHG emissions by: (i) having the U.S. rejoin the Paris Agreement (February 2021), (ii) announcing a new U.S. target to achieve a 50% to 52% reduction from 2005 levels in economy-wide net GHG pollution by 2030 (April 2021), and (iii) signing 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, President Trump signed an executive order directing the U.S. to withdraw from the Paris Agreement (January 2025), and it is expected that President Trump and the Republican-led Congress will diverge from the previous administration’s positions and GHG commitments.

The Inflation Reduction Act of 2022 imposes a tax, or "methane fee," on energy producers that exceed a certain level of methane emissions.  In January 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 GHG emissions associated with our operations.  However, future emission reduction targets and other provisions of legislative or regulatory initiatives and policies enacted in the future by the U.S. could be brought by future administrations or, in the absence of federal action, states may become more active and focused on taking legislative or regulatory actions aimed at climate change and minimizing GHG emissions.

Federal and state requirements to reduce GHG 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 GHGs 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 GHG 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.

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.

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.

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 economic 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 economic 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.

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 numerous factors, many of which are beyond our control. These factors include:

In recent years, increasing attention to environmental, social, and governance matters, including those related to climate change and sustainability, increasing societal, investor and legislative pressure on companies to address environmental, social, and governance 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 environmental, social, and governance 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 environmental, social, and governance 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 environmental, social, and governance matters, including biodiversity, waste, and water, may increase costs, require changes in how we operate and lead to negative shareholder sentiment.

Conversely, environmental, social, and governance has become a politically charged issue, and “anti-environmental, social, and governance” sentiment and increased scrutiny and skepticism of environmental, social, and governance policies and practices have resulted in, and could continue to result in, additional demands and strains on companies.  Responding to such environmental, social, and governance focused activism has been, and will likely continue to be, costly and time-consuming. Such response efforts have resulted in, and could continue to result in, the implementation of certain practices and disclosures that may present a heightened level of legal and regulatory risk, or that threaten our credibility with other investors and stakeholders. The methodologies and standards for tracking and reporting on environmental, social, and governance matters are relatively new, have not been standardized, and continue to evolve. As a result, our environmental, social, and governance related metrics, targets, ambitions, and other disclosures, may not necessarily be calculated or presented in the same manner or be comparable to similarly titled measures presented by us in other contexts, or by other companies or third-party estimates or disclosures, and our interpretation of reporting standards may differ from those of others. While we believe that our environmental, social, and governance disclosures and methodologies reflect our business strategy and are reasonable at the time made or used, as our business or applicable methodologies, standards, or regulations develop and evolve, we may revise or cease reporting or using certain disclosures and methodologies if we determine that they are no longer advisable or appropriate, or are otherwise required to do so.

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.

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, 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 enormous 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.

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.

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.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

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 9,961 square feet of office space in Houston, Texas. The location and general description of our other properties are described within “Part I. Item 1. Business—Downstream Operations, —Midstream Operations, and — Inactive Operations”.

ITEM 3.  LEGAL PROCEEDINGS

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, sometimes unspecified, damages or penalties may be sought from us in some matters, which 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  

RLI Corp. Surety Bonds. Blue Dolphin currently has several surety bonds through RLI Corp. 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 was collateralized in cash. In February 2024, RLI Corp. filed suit against Blue Dolphin, BDPL, and BDEX seeking an injunction for the payment of approximately $1.0 million of additional cash collateral for the bonds. BDPL filed its answer to RLI Corp.'s lawsuit in April 2024 denying RLI Corp.'s claims, and in July 2024 BDPL presented a settlement proposal to RLI Corp. to resolve the matter through a series of payments collateralizing the bonds with cash. In July 2024, RLI Corp. informed the court that the parties reached a settlement in principle, and the parties executed a settlement agreement in September 2024. From September to December 2024, BDPL made payments to RLI Corp. under the settlement agreement totaling $0.6 million. As of the filing date of this report, BDPL was in compliance with the settlement agreement with RLI Corp. Once complete, abandonment of BDPL’s offshore pipeline and platform assets will eliminate the need for all BOEM supplemental pipeline bonds, which would reduce the amount of surety bonds held by RLI Corp. from $1.25 million to $0.25 million.

Pilot Dispute Related to Terminal Services Agreement. As previously disclosed, NPS and Pilot were involved in a contract-related dispute involving to a Terminal Services Agreement pursuant to which NPS stored jet fuel purchased by Pilot at the Nixon facility. The parties entered into a confidential settlement agreement on December 29, 2023.  As part of the confidential settlement agreement, the parties agreed to mutually release all claims against each other.  Further, all contractual agreements between the parties, including the Terminal Services Agreement, were terminated.

TCEQ Final 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 believed the penalty matter is resolved in September 2023, TCEQ referred the matter to the State Office of Administrative Hearings ("SOAH"). A preliminary hearing, the purpose of which was to set a hearing schedule, was held on August 8, 2024; management participated in the hearing. Although a follow-up hearing was scheduled for January 2025, TCEQ presented, and LRM signed, a revised draft Agreed Order in November 2024.  Under the terms of the revised draft Agreed Order, TCEQ acknowledged that LRM had ceased unauthorized disposal of industrial solid waste and industrial hazardous waste and LRM accepted a final penalty amount of approximately $0.4 million, which will be paid in monthly installments over a three-year period. The SOAH case was dismissed and the matter was remanded back to the TCEQ December 2024; TCEQ finalized the Agreed Order in February 2025.  At both  December 31, 2024 and 2023, we accrued $0.4 million on our balance sheet within accrued expenses and other current liabilities related to this matter.

Unresolved Matters

Default under a Secured Loan Agreement. As of December 31, 2024 and the filing date of this report, certain of our bank debt to Veritex was in default related to a financial covenant violation, and bank debt to GNCU was in default related to non-financial covenant violations. See “Note (10)” to our consolidated financial statements for additional disclosures related to third-party debt, default on such debt, and the potential effects of such a default on our business, financial condition, and results of operations. If the lenders exercises their rights and remedies due to the defaults under our secured loan agreement, our business, financial condition, and results of operations will be materially adversely affected.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our Common Stock trades on the OTCQX U.S. tier of the OTC Markets under the ticker symbol “BDCO.” The quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions.  We had 14,921,968 shares of Common Stock issued and outstanding at both December 31, 2024 and 2023, respectively. Affiliates controlled 83.7% of our Common Stock's voting power as of this report's filing date. See “Part I, Item 1A. Risk Factors—Common Stock (Section E)” for risks associated with investments in our Common Stock.

Stockholders

We had 272 record holders at both December 31, 2024 and 2023. We had approximately 3,000 beneficial holders of our Common Stock at both December 31, 2024 and 2023.

Dividends

Stockholders are entitled to receive such dividends as may be declared by our Board out of funds legally available for such purpose. However, no dividend may be declared or paid unless after-tax profit was made in the preceding fiscal year, we comply with covenants in our secured loan agreements, we are current on all required debt payments, and we have received prior written concurrence from certain lenders.  We have not declared any dividends on our Common Stock during the last two fiscal years.

ITEM 6.  SELECTED FINANCIAL DATA

[Reserved]

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

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, 2024 and 2023 and a comparison between such periods. The discussions of the twelve months ended December 31, 2022 and year-to-year comparisons between the twelve months ended December 31, 2023 and 2022 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, 2023, which was filed on April 1, 2024, and such discussions are incorporated by reference into this report.

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.”

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 83.7% 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.  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.

Our Operations

Our assets are organized into two business segments:

Business Operations Update

For the twelve months ended December 31, 2024, refining margins were less favorable compared to the twelve months ended December 31, 2023.  Less favorable refining margins on lower sales volumes contributed to Blue Dolphin reporting a net loss of $8.6  million, or $0.58 per share, for the twelve months ended December 31, 2024 ("2024") compared net income of $31.0 million, or $2.08 per share, for the twelve months ended December 31, 2023 (“2023”).  Our full operating results for 2024 and 2023, including operating results by segment, can be found within ‘Results of Operations.’

We used cash flow from operations of $15.7 million for the twelve months ended December 31, 2024. The use of cash flow from operations was primarily due to a buildup of inventory.  Inventory increased due primarily to unfavorable product pricing, limited opportunities for customers who export to Mexico, and an intentional buildup of inventory by us during periods of low refining margins. At December 31, 2024, we had $0.1 million 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

Uncertainties remain surrounding general macroeconomic conditions related to inflation, tariffs, interest rates, capital and credit markets, and geopolitical tensions (including military conflicts in Ukraine and Israel and escalations in the Middle East). We do not operate or own assets in Russia, Ukraine, or the Middle East. However, the extent to which these factors impact our working capital, commodity prices, refined product demand, 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. While it is difficult to predict the ultimate economic impacts of these factors on our operations, below are key factors that impacted our results of operations in 2024 and will likely impact our results of operations during 2025:

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 lenders 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.

Liquidity and Access to Capital Markets

We continue efforts to improve our balance sheet. During 2024 and 2023, we entered into payment agreements with the Kissick Noteholder and LEH related to our secured loan agreements, and we continue to engage with potential lenders to obtain additional funding to refinance and restructure our debt. 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 our 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 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 operations.

Regulation Changes

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 GHG 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.

2024 Business Strategy and Accomplishments

We have outlined the below strategic business objectives to improve our financial profile and refining margins.  These objectives are modified, as necessary, to reflect changing economic conditions and other circumstances.

Optimize Existing Asset Base. During the twelve months ended December 31, 2024, the Nixon facility underwent two planned maintenance turnarounds -- one major (13 days) and one minor (9 days).  Optimizing the Nixon refinery's processing units through maintenance turnarounds leverages our ability to meet customer demand and manage refining margins.  Additional improvements to the Nixon facility during the twelve months ended December 31, 2024 included the addition of anti-icing chemical storage, an upgrade to the chiller system, and installation of a 'cool down room' to reduce heat-related injuries for personnel, contractors, and drivers.

Improve Operational Efficiencies. During the twelve months ended December 31, 2024 we completed the upgrade of the Nixon facility's terminal management software.  Capital expenditures associated with the upgrade totaled $0.05 million during the twelve months ended December 31, 2024.  As a result of project completion, key elements of the plant's terminal loading functions are automated, improving order management, bills of lading delivery, and reporting.

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 had been attributable to numerous factors, including growing public support, U.S. governmental actions to increase energy independence, and environmental concerns related to climate change. While the Biden Administration advanced significant climate-related initiatives, including incentives to promote renewable energy, recent changes under the Trump Administration following the 2024 U.S. presidential election have begun to and may further shift regulatory priorities away from renewable energy. Through executive orders and regulatory rollbacks, certain Biden-era initiatives have been curtailed or reevaluated and incentives to increase fossil fuel production have been promoted, creating a more uncertain regulatory landscape which may materially impact our plans to capture renewable energy opportunities. Throughout 2024, management had meaningful discussions with potential commercial partners. However, 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 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.

Results of Operations

Below is a discussion and analysis of the factors contributing to our consolidated financial results of operations.  This information should be read in conjunction with our financial statements in “Part II, Item 8. Financial Statements and Supplementary Data.” While management intends for the financial statements, together with the following information, to provide investors with a reasonable basis for assessing our historical operations, 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 barrel 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. For example, if the price per barrel of crude oil increases, the price of jet fuel per barrel will also generally increase, as jet fuel is a refined product derived from crude oil.  Therefore, the effect of crude oil commodity price changes on our finished petroleum product commodity prices 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 2025 remains unclear given uncertainties surrounding general macroeconomic conditions related to inflation, tariffs, interest rates, capital and credit markets, and geopolitical tensions (including military conflicts in Ukraine and Israel and escalations in the Middle East). We can provide no assurances that refining margins will be positive and demand will increase.

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: Earnings before interest, income taxes, and depreciation and amortization ("EBITDA") on a consolidated and segment basis, refinery throughput, production and sales data, refinery downtime, tolling and terminaling revenue, and intercompany processing fees.  We modified our segment presentation to incorporate applicable depreciation and amortization into our cost of goods sold subtotal. We believe this provides a more complete representation of our cost of goods sold. Prior periods have been modified to conform with this presentation.

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.

2024 Versus 2023.

Overview. Net loss for 2024 was $8.6 million, or $0.58 per share, compared to net income of $31.0 million, or $2.08 per share, in 2023. The $39.6 million, or $2.66 per share, decrease in net income between the periods was the result of less favorable refining margins and lower sales volumes. The Nixon refinery was down for 27 days in 2024 relating to pre-planned maintenance turnarounds (22 days), maintenance and repairs (2 days), and freezing weather conditions (3 days).  The Nixon refinery was down for 12 days in 2023 relating to a pre-planned maintenance turnaround (3 days) and maintenance and repairs (9 days).

Total Revenue from Operations.  Total revenue from operations was $317.5 million for 2024 compared to total revenue from operations of $396.0 million for 2023, representing a decrease of 19.8%. The decrease in 2024 related to declines in both refinery operations and tolling and terminaling revenue. Refinery operations revenue in 2024 decreased primarily due to lower market pricing and nearly 11% lower sales volumes; tolling and terminaling revenue in 2024 declined primarily due to lower tank rental fees. Tank rental fees for 2023 included temporary terminal service fees associated with Pilot. 

Total Cost of Goods Sold. Total cost of goods sold was $313.6 million for 2024 compared to total cost of goods sold of $353.9 million for 2023, representing a decrease of 11.4%. The decrease in 2024 related to lower sales volume and market pricing associated with product sales mix.

Gross Profit. Gross profit totaled $3.9  million for 2024 compared to gross profit of $42.1 million for 2023. Less favorable commodity prices and nearly 11% lower sales volume adversely impacted refinery operations gross profit in 2024 compared to 2023.

LEH Operating Fee, Related Party.  For 2024 the LEH operating fee, related party totaled $0.8 million compared to $0.5 million for 2023, representing a 52.2%  increase. The increase related to turnaround expenses and higher conversion costs.

Other Operating Expenses.  Other operating expenses totaled $0.6 million for 2024 compared to $0.2 million for 2023. The $0.4 million, or 207.7% increase related to decommissioning of our pipeline assets.

General and Administrative Expenses. General and administrative expenses totaled $6.4 million in 2024 compared to other operating and general and administrative expenses of $3.1 million in 2023. The $3.3 million, or 105.6%, increase in 2024 primarily related to professional service fees, insurance, and regulatory penalties.

Interest and Other Non-Operating Expenses, Net. Total other expense in 2024 was flat compared to 2023, totaling $5.9 million for both periods. Total other expense primarily relates to interest expense associated with related party-party and third-party secured loan agreements.

Consolidated EBITDA. Consolidated EBITDA in 2024 totaled $1.5 million compared to $39.2 million in 2023, representing a decrease of $40.7 million. The significant decrease in 2024 was related to less favorable refining margins, 10.7% lower sales volume, an $8.3 million inventory impairment due to recognizing inventory at the lower of cost or net realizable value, maintenance turnaround expenses, and lower tolling and terminaling total revenue.

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.

2024 Versus 2023

Total refined product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

Refinery Downtime. Refinery downtime increased from 12 days in 2023 to 27 days in 2024. Refinery downtime in 2024 related to pre-planned maintenance turnarounds (22 days), maintenance and repairs (2 days), and freezing weather conditions (3 days).  Refinery downtime in 2023 related to a pre-planned maintenance turnaround (3 days) and maintenance and repairs (9 days).

Refinery Operations Revenue.  Refinery operations revenue was $313.6 million for 2024 compared to $390.0 million for 2023, representing a decrease of 19.6%. The decrease in 2024 related to lower market pricing and lower sales volumes.

Cost of Goods Sold.  Cost of goods sold for refinery operations was $310.6 million for 2024 compared to $350.9 million for 2023, representing a decrease of 11.5%.  The  decrease in 2024 was related to lower sales volume and market pricing associated with product sales mix.

LEH Operating Fee, Related Party.  For 2024 the LEH operating fee, related party totaled $0.8 million compared to $0.5 million for 2023, representing a 52.2%  increase. The increase related to turnaround expenses and higher conversion costs.

Refining EBITDA. Refining EBITDA was $2.3 million in 2024 compared to $38.6 million in 2023, representing a decrease of 94.2%. The significant decrease in 2024 was related to less favorable refining margins and 10.7% lower sales volume.  Refining EBITDA was adversely impacted by maintenance turnaround expenses and an $8.3 million inventory impairment due to recognizing inventory at the lower of cost or net realizable value.

Refining Operations EBITDA per Bbl. On a per barrel basis, refining EBITDA was $0.61 for 2024 compared to $9.37 for 2023, representing a decrease of $8.76 per barrel. The decrease in 2024 related to less favorable refining margins and 10.7% lower sales volume compared to the same period a year earlier.

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 in-tank blending), and tolling and reservation fees for use of the naphtha stabilizer.

2024 Versus 2023

Tolling and Terminaling Total Revenue. Tolling and terminaling total revenue was $3.9 million in 2024 compared to $6.0 million in 2023, representing a decrease of 34.7%.  The decrease in 2024 related to lower tank rental fees. Tank rental fees in 2023 included temporary terminal service fees associated with Pilot. 

Tolling and Terminaling EBITDA.  We had tolling and terminaling EBITDA of $2.1 million in 2024 compared to $4.3 million in 2023, representing a decrease of $2.2 million.  The significant decrease in 2024 compared to 2023 related to lower tolling and terminaling total revenue.

Non-U.S. GAAP Measures.

The following are non-U.S. GAAP measures we present for the years ended December 31, 2024 and 2023:

Consolidated EBITDA.  Income (loss) before interest, taxes, and depreciation and amortization on a consolidated basis.

Refining EBITDA. Income (loss) before interest, taxes, and depreciation and amortization for our refinery operations business segment.

Refining operations EBITDA per bbl. Refining EBITDA divided by sales (Mbbls) for the reporting period.

Tolling and terminaling EBITDA. Income (loss) before interest, taxes, and depreciation and amortization for our tolling and terminaling business segment. 

We present these measures because they provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluation of our performance relative to our peers, and (iii) supplemental information to investors about certain material non-cash and other items that may not continue at the same level in the future. EBITDA has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under U.S. GAAP or as alternatives to net income (loss), operating income (loss), gross margin, or any other measure of financial performance presented in accordance with U.S. GAAP. 

Capital Resources and Liquidity

Working Capital. 

We had a working capital deficit of $19.1 million at December 31, 2024 compared to a working capital deficit of $6.1 million at December 31, 2023, representing a $13.0 million decrease. Our significant debt in current liabilities at December 31, 2024 consisted of bank debt to Veritex and GNCU and related-party debt. Excluding accrued interest, we had current related-party and third-party debt of $40.6 million and $39.4 million as of December 31, 2024 and 2023, respectively. The $1.2 million increase in current debt between the periods primarily related to a $3.3 million draw under the Affiliate Revolving Credit Agreement offset by loan payments. We continue to engage with potential lenders to obtain additional funding to refinance and restructure debt and further improve working capital.

Our current assets totaled $44.8 million at December 31, 2024 compared to $49.3 million at December 31, 2023, representing a $4.5 million decrease. Our current liabilities totaled $63.9 million at December 31, 2024 compared to $55.4 million at  December 31, 2023, representing a $8.5 million increase.

Liquidity. Cash and cash equivalents totaled $0.1 million and $18.7 million at December 31, 2024 and 2023, respectively, representing a decrease of $18.6 million. A significant portion of our liquidity at December 31, 2024 was invested in inventory.  Restricted cash, current totaled $1.0 million and $0.0 at December 31, 2024 and 2023, respectively. Restricted cash, current related to a Veritex payment reserve account. Although the payment reserve account had a balance of $0.0 at December 31, 2023, the account was fully replenished on January 2, 2024.  Accounts receivable—related party, which was associated with the sale of jet fuel to LEH, totaled $5.2  million and $4.2 million at December 31, 2024 and 2023, 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 efforts to improve our balance sheet. During 2024 and 2023, we entered into payment agreements with the Kissick Noteholder and LEH related to our secured loan agreements, and we continue to engage with potential lenders to obtain additional funding to refinance and restructure debt. 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, tariffs, 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 operations.

Sources and Use of Cash.

Components of Cash Flows.

Cash Flow from Operations.  We used $15.7 million in cash flow from operations during the twelve months ended December 31, 2024 compared to generating $20.0 million in cash flow from operations during the twelve months ended December 31, 2023. The $35.7 million decrease in cash flow used from operations between the periods was primarily due to a buildup of inventory in 2024 and lower refining margins.  Inventory increased due primarily to unfavorable product pricing, limited opportunities for customers who export to Mexico, and an intentional buildup of inventory by us during periods of low refining margins.

Capital Expenditures. Capital expenditures totaled $0.0 for the twelve months ended December 31, 2024 compared to capital expenditures of $0.1 million for the twelve months ended December 31, 2023. Due to continued uncertainties surrounding general macroeconomic conditions related to inflation, tariffs, interest rates, capital and credit markets, and geopolitical tensions (including military conflicts in Ukraine and Israel and escalations in the Middle East), we anticipate continuing to limit capital expenditures for the remainder of 2025. 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 capital expenditures in accordance with U.S. 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. Management determines projects 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 or lowering future expenses.

Financing Activities.  During the twelve months ended December 31, 2024, Blue Dolphin made payments on debt principal totaling $5.2 million compared to payments on debt principal totaling $1.5 for the twelve months ended December 31, 2023. Proceeds from debt totaled $3.3 million for the twelve months ended December 31, 2024 compared to proceeds from debt totaling $0.0 for the twelve months ended December 31, 2023.  In 2024, proceeds from debt related to the Affiliate Revolving Credit Agreement. In 2023, Blue Dolphin paid off amounts owed to LEH totaling $1.2 million related to a June 2017 promissory note, as amended, for Blue Dolphin working capital. See "Part II, Item 8. Financial Statements and Supplementary Data —Notes (3) and (16)" to our consolidated financial statements for additional disclosures related to related-party transactions.

Debt and Lease Obligations.

Debt Agreements.

Related-Party Agreements Summary. Blue Dolphin and certain of its subsidiaries are parties to the following debt agreements with related parties:

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

Guarantees and Security.