BLUE DOLPHIN ENERGY CO - Annual Report: 2022 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2022

 or

For the transition period from ___________ to ____________ 

 Commission File No. 0-15905

713-568-4725  

(Registrant’s telephone number, including area code)  

Securities registered pursuant to Section 12(b) of the Act: None 

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.  Yes ☐ No ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).  Yes ☐ No ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate market value of shares of common stock held by non-affiliates of the registrant was $2,919,215 as of June 30, 2022 (the last trading day of the registrant’s most recently completed second fiscal quarter) based on the number of shares of common stock held by non-affiliates and the last reported sale price of the registrant's common stock on June 30, 2022.

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, 2022.  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, 2021.

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 United States.  Operations primarily consist of a light sweet-crude, 15,000-bpd crude distillation tower, and approximately 1.2 million bbls of petroleum storage tank capacity in Nixon, Texas.  Blue Dolphin trades on the OTCQX under the ticker symbol "BDCO."

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

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

Going Concern

In accordance with GAAP accounting standards, we evaluated whether there are conditions and events, considered in the aggregate, that raise substantial doubt about our ability to continue as a going concern within one year after the date that our consolidated financial statements are issued. While results of operations were significantly improved for the twelve months ended December 31, 2022 versus the prior twelve month period, management determined that certain factors continue to present substantial doubt about our ability to continue as a going concern. These factors include significant current debt, which impacts our ability to meet debt covenants, and historical net losses and working capital deficits. Our consolidated financial statements assume we will continue as a going concern and do not include any adjustments that might result from this uncertainty.  Management is working to alleviate these factors by entering into forbearance agreements with lenders, maximizing operation of the Nixon refinery given favorable refining margins, and pursuing opportunities to obtain capital and/or refinance debt.

Our significant current debt is the result of certain third-party and related-party loan agreements being classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2022 and 2021. Excluding accrued interest, we had current debt of $47.4 million and $63.0 million, respectively, as of December 31, 2022 and 2021. Our significant current debt consists of bank debt to Veritex and GNCU, investor debt to John Kissick, and related party debt to LEH.

Forbearance Agreement

Pursuant to the November 2022 Veritex Forbearance Agreement, Veritex agreed to forbear from exercising any of its rights and remedies related to existing defaults pertaining to covenant violations under the LE Term Loan Due 2034 and LRM Term Loan Due 2034 for a period beginning on November 18, 2022 through September 30, 2023.  During the forbearance period, Veritex agreed to forbear from testing borrowers’ compliance with financial covenants as specified in the LE Term Loan Due 2034 and LRM Term Loan Due 2034 and forbear from exercising its rights or remedies with respect to non-compliance with the financial covenants. As part of the Veritex Forbearance Agreement, LE and LRM paid Veritex: (i) $4.3 million in past due principal and interest at the non-default rate (excluding late fees), (ii) $1.0 million into a payment reserve account, and (iii) $0.04 million in Veritex attorney fees.  In the event that LE and LRM pay off all amounts due under the LE Term Loan Due 2034 and LRM Term Loan Due 2034 on or before September 30, 2023, Veritex also agreed to waive late fees totaling approximately $0.4 million in the aggregate.  The Veritex Forbearance Agreement shall terminate on the first to occur: September 30, 2023, failing to  make a payment when due, breach, or any new event of default.  As of December 31, 2022 and the filing date of this report, LE and LRM were in compliance with the Veritex Forbearance Agreement.

Other Defaults

We are in default under the NPS Term Loan Due 2031 due to covenant violations.  We are also in default under the Kissick Debt, June LEH Note, and BDPL-LEH Loan agreement related to past due obligations at maturity. Defaults permit the lender to declare the amounts owed under the related loan agreements immediately due and payable, exercise their rights with respect to collateral securing obligors’ obligations, and/or exercise any other rights and remedies available.

Favorable Refining Margins

The strong demand for our products, particularly jet fuel, and the increase in refining margins were the primary contributors to us reporting $32.9 million in net income for the twelve months ended December 31, 2022. Comparatively, we reported a net loss of $12.8 million for the twelve months ended December 31, 2021. Our operating results for 2022, including operating results by segment, can be found within ‘Results of Operations’ in “Part II, Item 7. Management’s Discussion and Financial Analysis of Financial Condition and Results of Operations” in this report.

Our results of operations and liquidity are highly dependent upon the margins that we receive for our refined products. The dollar per bbl commodity price difference between crude oil and condensate (input) and refined products (output) is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. While refining margins and liquidity improved significantly during 2022, the general outlook for the oil and natural gas industry for 2023 remains unclear given uncertainty surrounding the Russian military conflict with Ukraine, COVID-19, recession, and inflation. We can provide no assurances that refining margins and demand will remain at current levels.

Working Capital Improvements

Historically, we experienced net losses during three of the last five years.  We had $45.2 million and $78.5 million in working capital deficits at December 31, 2022 and 2021, respectively.  Excluding the current portion of long-term debt, we had $2.1 million in working capital and $15.5 million in working capital deficits at December 31, 2022 and 2021, respectively. The significant improvement in working capital between the twelve-month periods ended December 31, 2022 and 2021 was primarily due to favorable refining margins and increased gross profit. Continued favorable market conditions will enable us to continue meeting our needs through cash flow from operations. We also continue to explore opportunities to obtain capital and/or refinance debt.  During the twelve months ended December 31, 2022 and 2021, we successfully secured $1.5 million and $10.5 million, respectively, in working capital through CARES Act loans. In October 2021, NPS repaid all obligations owed to Pilot under the Amended Pilot Line of Credit.

Our ability to continue as a going concern depends on sustained positive operating margins and adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on long-term debt.  If we are unable to process crude oil and condensate into sellable refined products or make required debt payments, we may consider other options. These options could include selling assets, raising additional debt or equity capital, cutting costs, reducing cash requirements, restructuring debt obligations, or filing bankruptcy.

Operating Risks

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

The Russian military conflict with Ukraine, COVID-19, recession, and inflation continue to evolve, 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, or if Tartan terminates the Crude Supply Agreement, our business, financial condition, and results of operations will be materially adversely affected.

Downstream Operations

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

Crude Oil and Condensate Supply.  Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. We have a long-term crude supply agreement in place with Tartan.  The volume-based Crude Supply Agreement expires when we receive 24.8 million net bbls of crude oil.  After that, the Crude Supply Agreement automatically renews for successive one-year terms (each such term, a renewal term).  Tartan must provide notice of non-renewal at least 60 days before the expiration of any renewal term.  For the twelve months ended December 31, 2022 and 2021, we received approximately 4.5 million bbls, or 18.4%, and 4.2 million bbls, or 17.0%, respectively, of the contracted volume under the Crude Supply Agreement.  As of December 31, 2022, we received approximately 13.6 million bbls, or 54.8%, of the total allowable contracted volume under the Crude Supply Agreement.  At December 31, 2022, accounts payable for crude oil and condensate was $0. As of December 31, 2022, 100% of our crude oil was sourced from Tartan under the Crude Supply Agreement.

Related to the Crude Supply Agreement, Tartan stores crude oil at the Nixon facility under a terminal services agreement dated as of June 1, 2019.  Under the terminal services agreement, crude oil is stored at the Nixon facility at a specified rate per bbl of the storage tank’s shell capacity.  The terminal services agreement renews on a one-year evergreen basis.  Tartan must provide notice of non-renewal at least 60 days before the expiration of any renewal term.  However, the terminal services agreement will automatically terminate upon expiration or termination of the Crude Supply Agreement.

Our financial health has been materially and adversely affected by significant current debt, certain of which is in default, historical net losses and working capital deficits, and margin volatility.  If Tartan terminates the Crude Supply Agreement or terminal services agreement, our ability to acquire crude oil and condensate could be adversely affected. 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 would result in refinery downtime and could materially affect our business, financial condition, and results of operations. To mitigate this risk, we are exploring other crude supply sources. 

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

The Nixon refinery’s product slate is adjusted based on market demand. We currently produce a single finished product – jet fuel – and several intermediate products, including naphtha, HOBM, and AGO.  Our jet fuel is sold to an Affiliate, which is HUBZone certified.  The product sales agreement with the Affiliate has a one-year term expiring the earliest to occur of March 31, 2024 plus 30-day carryover or delivery of the maximum quantity of jet fuel.  Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing.

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

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

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

The Nixon refinery periodically undergoes planned and unplanned temporary shutdowns. We typically complete a planned turnaround annually to repair, restore, refurbish, or replace refinery equipment. However, the timing of planned turnarounds is adjusted to capitalize on favorable market conditions. Occasionally, unplanned shutdowns occur.  Unplanned downtime can occur for a variety of reasons; however, common reasons for unplanned downtime include repair/replacement of disabled equipment, crude deficiencies associated with cash constraints, high temperatures, and power outages.  In 2021, the Nixon refinery did not incur significant damage due to Winter Storm Uri; however, the facility lost external power for 10 days due to the storm.  In December 2022, the Nixon refinery was idled for 5 days due to an unnamed winter ice storm.

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

Midstream Operations

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

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

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

Inactive Operations

We own other pipeline and facilities assets and have leasehold interests in oil and gas properties.  These assets are inactive.  We account for these inactive operations in ‘corporate and other.’  Our pipeline assets have been fully impaired since 2016 and our oil and gas leasehold interests have been fully impaired since 2011. Our pipeline assets and oil and gas leasehold interests had no revenue during the twelve months ended December 31, 2022 and 2021.

Pipeline and Facilities Safety. 

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

Insurance and Risk Management

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

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

Intellectual Property

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

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.

Human Capital Management

General.  Our operations and activities are managed by an Affiliate.  We do not have any employees. As of December 31, 2022, 116 employees of the Affiliate provided support for our operations pursuant to the Amended and Restated Operating Agreement. None of these employees were covered by collective bargaining agreements.  Under the Amended and Restated Operating Agreement, the Affiliate operates and manages all of our properties.

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

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

We have developed and implemented a COVID-19 mitigation plan based on CDC and state health guidelines. This plan includes the implementation of health-screening protocols, elevated cleaning measures, reduced shared spaces, the purchase of masks for all personnel for use when social-distancing measures are not possible, and providing work-from-home support to facilitate remote working. Although vaccines have not been mandated, we have actively communicated updates to our workforce regarding vaccine availability and have encouraged eligible personnel to get vaccinated.

Inclusion and Diversity.  We continue to evaluate measures to put in place and track our progress with regard to diversity and inclusion. As of December 31, 2022, employees of the Affiliate self-identified as 38% White, 37% Hispanic Latino, 18% Black or African American, and 1% Asian.

Government Regulations

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

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

The EPA has undertaken significant regulatory initiatives 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 been targeted at 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 this ongoing NSR/PSD regulatory initiative, the EPA has 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.  If selected, as a small refiner we do not expect any additional requirements to have a material impact on our financial position, results of operations, or liquidity.

The EPA strengthened the NAAQS for ground-level ozone to 70 parts per billion in 2015 from the 75-parts per billion level set in 2008. To implement the revised ozone NAAQS, all states will need to review their existing air quality management infrastructure State Implementation Plan for ozone and ensure it is appropriate and adequate. Where areas remain in ozone non-attainment or come into ozone non-attainment as a result of the revised NAAQS, it is likely that additional planning and control obligations will be required. States may impose additional emissions control requirements on stationary sources, changes in fuels specifications, and changes in fuels mix and mobile source emissions controls. The ongoing and potential future requirements imposed by states to meet the ozone 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 that does not fall under RFS or RFS2 compared to low sulfur diesel.

Currently, multiple legislative and regulatory measures to address greenhouse gas emissions are in various phases of discussion or implementation.  These include actions to develop national, state, or regional programs, each of which would require reductions in our greenhouse gas emissions or those of our customers.  In 2015, the EPA amended the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program, to include among other things a new Onshore Petroleum and Natural Gas Gathering and Boosting segment that encompasses greenhouse gas emissions from equipment and sources within the petroleum and natural gas gathering boosting systems.  In 2016, the EPA promulgated regulations regarding performance standards for methane emissions from new and modified oil and gas production and natural gas processing and transmission facilities, and in September 2018, proposed targeted improvements to these standards to streamline implementation of the rules.  These and other legislative regulatory measures will impose additional burdens on our business and those of our customers.

In 2021, the Biden Administration signaled that it will take steps intended to address climate change.  In January 2021, the White House issued an Executive Order titled “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,” as well as a formal notification re-accepting the United States’ re-entry into the Paris Agreement. Also in January 2021, the White House issued another climate-related Executive Order, titled “Tackling the Climate Crisis at Home and Abroad.” In April 2021, the Biden Administration announced a new target for the United States to achieve a 50 to 52 percent reduction from 2005 levels in economy-wide net greenhouse gas emissions in 2030. The EPA’s approach to regulating GHG emissions may change, including under future administrations. Therefore, future impact of the Biden Administration’s executive orders and future GHG regulations on our operations and financial condition is unknown.

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

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

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

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.

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

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

Offshore “Idle Iron” Decommissioning Regulations. In 2018 BSEE updated its guidance and regulations on decommissioning that mandates lessees and rights-of-way holders permanently abandon and/or remove platforms and other structures when no longer useful for operations.  To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the minimum bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM.      

We are required by BOEM to: (i) maintain acceptable financial assurance (pipeline bonds) for the decommissioning of our assets offshore in federal waters and (ii) decommission these assets following a certain period of inactivity. As of December 31, 2022, we maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM.  At December 31, 2022 and 2021, BDPL maintained $3.7 and $3.5 million, respectively, in AROs related to abandonment of these assets.  See “Part I, Item 1A. Risk Factors” for additional disclosures related to idle iron decommissioning requirements for our pipelines and facilities assets and related risks.

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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.

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

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

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

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.

In this challenging business environment, we continuously monitor our assets for impairment, as well as optimization opportunities. We recorded an impairment of $0.1 million and $1.1 million related to asset retirement costs for our pipeline/platform assets as of December 31, 2022 and 2021, respectively.  An additional impairment may be required in future periods if instabilities in the market continue long-term, losses continue to be material, or as new opportunities arise, such as reconfiguration of the Nixon refinery into a renewable fuels facility.

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

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.  We reflect such borrowings in our consolidated balance sheets in accounts payable, related party, or long-term debt, related party.  At both December 31, 2022 and 2021, accounts payable, related party totaled $0.2 million.  At December 31, 2022 and 2021, long-term debt, related party, current portion (in default) and accrued interest payable, related party totaled $9.3 million and $23.5 million, respectively.

If we are unable to generate sufficient cash flows or otherwise secure sufficient liquidity from Affiliates or external financing, 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 Amended and Restated Operating Agreement, (iii) servicing debt, (iv) maintaining and expanding the Nixon facility through capital expenditures, and (v) meeting regulatory compliance mandates. Our long-term working capital needs are primarily related to repayment of long-term debt obligations.

There can be no assurance that Affiliates will continue to fund our working capital requirements.  If we are unable to generate sufficient working capital or raise additional capital on acceptable terms, or at all, we may not, in the short term, be able to purchase crude oil and condensate or meet debt payment obligations. In the long term, we may not be able to withstand business disruptions, such as from COVID-19, or execute our business strategy. We may have to consider other options, such as selling assets, raising additional debt or equity capital, seek bankruptcy protection, or cease operating.

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

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

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

One of our significant customers is LEH, an Affiliate. Due to a HUBZone certification, the Affiliate purchases our jet fuel under a Jet Fuel Sales Agreement and bids on jet fuel contracts under preferential pricing terms.  The Affiliate accounted for 35.6% and 29.9% total revenue from operations for the twelve months ended December 31, 2022, and 2021, respectively.  The Affiliate represented $0 in accounts receivable at both December 31, 2022, and 2021.

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

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 of the risks and operational hazards inherent in receiving, handling, storing, and transferring crude oil and petroleum products, including: 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) at our facilities or at third-party facilities on which our operations are dependent could result in 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 new technologies at substantial costs to achieve our strategy. These uncertainties and costs could cause us to not be able to fully implement or realize the anticipated results and benefits of our business strategy.

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

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. For example, President Biden has issued an executive order seeking to adopt new regulations and policies to address climate change and to consider suspending, revising, or rescinding prior agency actions that are identified as conflicting with the Biden Administration’s climate policies. The current administration may take further actions that could restrict or limit operations as currently conducted at the Nixon Facility.

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

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, and the U.S. and certain other countries could impose further sanctions, trade restrictions, and other retaliatory actions should the conflict continue or worsen. It is not possible to predict the broader consequences of the conflict, including related geopolitical tensions, and the measures and retaliatory actions taken by the U.S. and other countries in respect thereof as well as any counter measures or retaliatory actions by Russia in response, including, for example, potential cyberattacks or the disruption of energy exports, is likely to cause regional instability, geopolitical shifts, and could materially adversely affect global trade, currency exchange rates, regional economies and the global economy. On year later, the situation remains uncertain, and while it is difficult to predict the impact of any of the foregoing, the conflict and actions taken in response to the conflict 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.

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 general economic conditions, unemployment, consumer debt, recession, inflation, reductions in net worth based on declines in equity markets and residential real estate values, adverse developments in mortgage markets, taxation, energy prices, interest rates, consumer confidence and other macroeconomic factors. Political instability and global health crises, such as COVID-19, can also impact the global economy and decrease worldwide demand for oil and refined products. During a period 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. The 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.

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

BDPL historically maintained $0.9 million in financial assurance to BOEM for the decommissioning of its trunk pipeline offshore in federal waters. Following an agency restructuring of the financial assurance program, in March 2018 BOEM ordered BDPL to provide additional financial assurance totaling approximately $4.8 million for five (5) existing pipeline rights-of-way. 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 milestones identified in an August 2019 meeting between management and BSEE may help in future discussions with BOEM related to the INCs. Decommissioning of these assets will significantly reduce or eliminate the amount of financial assurance 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 financial assurance (supplemental pipeline bond) requirements. If BDPL is required by BOEM to provide significant additional financial assurance (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 are currently unable to predict the outcome of the BOEM INCs. Accordingly, we did not record a liability on our consolidated balance sheets as of December 31, 2022 and 2021. At both December 31, 2022 and 2021, BDPL maintained approximately $0.9 million in pipeline rights-of-way surety bonds issued to BOEM through RLI Corp. Of the pipeline rights-of-way bonds, $0.7 million was credit-backed and $0.2 million was cash-backed.

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

In December 2018, BSEE issued an INC to BDPL for failing to flush and fill Pipeline Segment No. 13101. Management met with BSEE in August 2019 to address BDPL’s plans with respect to decommissioning its offshore pipelines and platform assets. BSEE proposed that BDPL re-submit pipeline and platform decommissioning permit applications, including a safe boarding plan, by February 2020. BDPL submitted permit applications to BSEE in February 2020 and the USACOE in March 2020. In April 2020, BSEE issued another INC to BDPL for failing to perform the required structural surveys for the GA-288C Platform. BDPL completed the required platform surveys in June 2020.

In August 2022, BSEE issued an INC to BDPL for failing to complete decommissioning its main offshore pipeline and anchor platform. In addition, pursuant to a September 2022 letter, BSEE ordered BDPL to complete pipeline decommissioning and removal of the anchor platform by June 1, 2023. BDPL is examining the feasibility of completing decommissioning operations by BSEE’s deadline. In March 2023, BSEE issued an INC to BDPL for failing to perform the required structural surveys for the GA-288C platform for 2021 and 2022, and for failing to provide BSEE with such survey results. BDPL is obtaining vendor quotes for the performance of the required surveys and intends to submit a corrective action plan to BSEE. If BDPL fails to complete decommissioning of the offshore pipeline and platform assets and/or remedy the INCs within the timeframe mandated by BSEE, BDPL could be subject to regulatory oversight and enforcement, including but not limited to failing to correct an INC, civil penalties, and revocation of BDPL’s operator designation, which could have a material adverse effect on our earnings, cash flows, and liquidity.

We cannot currently estimate when decommissioning may occur or predict the outcome of the BSEE INCs. Accordingly, we did not record a liability related to potential penalties on our consolidated balance sheets as of December 31, 2022 and 2021. At December 31, 2022 and 2021, BDPL maintained $3.7 million and $3.5 million, respectively, in AROs related to abandonment of these assets, which amount does not include potential penalties.

Process Safety Management Violations (OSHA). In September 2022, we entered into an Informal Settlement Agreement with OSHA related to process safety management violations at the Nixon refinery. Under the agreement, we paid penalties totaling $0.05 million in November 2022. We remediated a significant portion of identified violations prior to December 31, 2022. Most of the remaining violations were remediated prior to March 31, 2023. Work on the final violation is in progress, and we expect to complete the work in April 2023. Failing to abide by the terms of the agreed could result in additional fines.

Alleged Hazardous Waste Violations (TCEQ). 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 approximately $0.4 million and identified actions needed to correct the alleged violations. We are currently seeking to negotiate a reduced penalty amount. In May 2022, management met with the TCEQ to review the alleged solid hazardous waste violations. As follow-up to the meeting, LRM provided additional documentation to the TCEQ in a June 2022 letter. On March 29, 2023, TCEQ requested a meeting in April 2023 to review LRM's submissions to date. We recorded a liability for the maximum proposed amount of $0.4 million on our consolidated balance sheets within accrued expenses and other current liabilities as of December 31, 2022 and 2021. We cannot currently estimate when the TCEQ hazardous waste matter will be resolved or predict the outcome of the violations.

We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and seabeds. We based asset retirement cost estimates on regulatory requirements and then current market rates for decommissioning and removal of assets with our given structural and water depth specifications. Estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. In addition, market rates for dive operations are subject to fluctuations based on season, fuel costs, insurance rates, equipment availability, and industry changes. 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.

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

Reducing greenhouse gas emissions has been a focus of the Biden Administration. In February 2021, the United States rejoined the Paris Agreement, and in April 2021 the Biden Administration announced a new target for the United States to achieve a 50-52 percent reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. These and similar regulations could require us to incur costs to monitor, report, and reduce greenhouse gas emissions associated with our operations.

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

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. For example, Russia’s recent invasion of Ukraine and resulting sanctions and export controls by the United States 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 United States. 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 United States. 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, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. 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 financial loss. Our industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. Our technologies, systems, networks, or other proprietary information, and those of our vendors, suppliers, and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss, or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial loss from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all the oil and gas distribution systems in the United States and abroad, which are necessary to transportation 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 United States 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 various factors, many of which are beyond our control. These factors include:

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

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, and/or warrants may significantly dilute the equity ownership of the current holders of our Common Stock, affect the rights of our stockholders, or could reduce the market price of our Common Stock. In addition, the issuance or sale of large amounts of our Common Stock, or the potential for issuance or sale even if they do not actually occur, may have the effect of depressing the market price of our Common Stock.

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.

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

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

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

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

BDSC Office Lease Default

In March 2021, BDSC defaulted on the office lease due to non-payment of rent. In May 2021, BDSC and TR 801 Travis LLC (“Building Lessor”) reached an agreement to cure BDSC’s office lease default. Under a Fourth Amendment to Lease dated May 27, 2021 (the “Fourth Amendment”), Building Lessor agreed to defer BDSC’s past due obligations, including rent installments and other charges totaling approximately $0.1 million (the “Past Due Obligations”), in equal monthly installments beginning in June 2021, and continuing through lease expiration.  The Past Due Obligations were subject to an annual percentage rate of 4.50%. As revised under the Fourth Amendment, BDSC’s base rent including  the prorated portion of the Past Due Obligations was $0.02 million per month.  Subsequent to the Fourth Amendment, Building Lessor notified BDSC of a new default under the office lease due to non-payment of rent.  As a result of the subsequent default, Building Lessor deemed the Fourth Amendment invalid.  On June 9, 2022, BDSC paid all past due amounts totaling approximately $0.2 million to Building Lessor and  Building Lessor considered the office lease default cured. The 68-month operating lease expires in August 2023. BDSC had an option to extend the lease term for an additional five (5) year period. However, BDSC is considering the economic advantages of alternative locations. 

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

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, and sometimes unspecified, damages or penalties may be sought from us in some matters and certain matters may require years to resolve. Although we cannot provide assurance, we believe that an adverse resolution of the matters described below would not have a material impact on our liquidity, consolidated financial position, or consolidated results of operations.

Unresolved Matters

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

On October 28, 2022, Pilot commenced an action and application for a temporary restraining order (“TRO”) against NPS in Harris County District Court (the “Texas Action”). After a hearing on the application on October 28, 2022, Pilot’s application for the TRO was denied the same day.

On December 2, 2022, NPS filed its answer in the Texas Action. On December 6, 2022, NPS provided notice under Section 7.206(a) of the Texas Business and Commerce Code (“TBCC”) of its intent to sell the remaining inventory of Pilot’s jet fuel at the Nixon facility by January 7, 2023. After a series of negotiations, NPS agreed to forbear from exercising its remedies under the TBCC while the parties explored a potential compromise of the dispute. The parties entered a Forbearance and Accommodation Agreement on January 12, 2023, with the forbearance period terminating on February 28, 2023.  As part of the Forbearance and Accommodation Agreement, Pilot paid NPS approximately $1.481 million on January 13, 2023. 

On March 31, 2023, NPS and Pilot executed an Amendment to the Forbearance and Accommodation Agreement (“March 31 Amendment") with the forbearance term extending to June 15, 2023.  The March 31 Amendment requires an additional payment by Pilot to NPS of approximately $1.08 million on April 3, 2023 and a conditional payment of $0.18 million on June 1, 2023. 

Pursuant to the March 31 Amendment all deadlines in the Texas Action have been tolled through June 15, 2023.

As of the filing date of this report, no settlement has been reached. 

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

BDPL historically maintained $0.9 million in financial assurance to BOEM for the decommissioning of its trunk pipeline offshore in federal waters.  Following an agency restructuring of the financial assurance program, in March 2018 BOEM ordered BDPL to provide additional financial assurance totaling approximately $4.8 million for five (5) existing pipeline rights-of-way.  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 milestones identified in an August 2019 meeting between management and BSEE may help in future discussions with BOEM related to the INCs. Decommissioning of these assets will significantly reduce or eliminate the amount of financial assurance 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 financial assurance (supplemental pipeline bond) requirements.  If BDPL is required by BOEM to provide significant additional financial assurance (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 are currently unable to predict the outcome of the BOEM INCs.  Accordingly, we did not record a liability on our consolidated balance sheets as of December 31, 2022 and 2021.  At both December 31, 2022 and 2021, BDPL maintained approximately $0.9 million in pipeline rights-of-way surety bonds issued to BOEM through RLI Corp.  Of the pipeline rights-of-way bonds, $0.7 million was credit-backed and $0.2 million was cash-backed.

OSHA Settlement Agreement.   In September 2022, we entered into an Informal Settlement Agreement with OSHA related to process safety management violations at the Nixon refinery.  Under the agreement, we paid penalties totaling $0.05 million in November 2022.  We remediated a significant portion of identified violations prior to December 31, 2022.  Most of the remaining violations were remediated prior to March 31, 2023. Work on the final violation is in progress, and we expect to complete the work in April 2023. Failing to abide by the terms of the agreed could result in additional fines.

TCEQ Proposed Agreed Order.  In October 2021, LRM received a proposed agreed order from the TCEQ for alleged solid and hazardous waste violations discovered during an investigation from January to March 2020.  The proposed agreed order assessed an administrative penalty of approximately $0.4 million and identified actions needed to correct the alleged violations. We are currently seeking to negotiate a reduced penalty amount.  In May 2022, management met with the TCEQ to review the alleged solid hazardous waste violations.  As follow-up to the meeting, LRM provided additional documentation to the TCEQ in a June 2022 letter.  On March 29, 2023, TCEQ requested a meeting in April 2023 to review LRM's submissions to date.  We recorded a liability for the maximum proposed amount of $0.4 million on our consolidated balance sheets within accrued expenses and other current liabilities as of December 31, 2022 and 2021.  We cannot currently estimate when the TCEQ hazardous waste matter will be resolved or predict the outcome of the violations.

Pilot Dispute Related to Set-Off Payments.  In October 2021, NPS repaid all obligations owed to Pilot under the Amended Pilot Line of Credit.  However, in a letter from NPS to Pilot dated October 28, 2021, NPS disputed approximately $0.3 million in set-off payments between Pilot and NPS.  As of the filing date of this report, the amount remained in dispute between the parties.

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

Counterparty Contract-Related Dispute.  As of the filing date of this report, we were involved in a contract-related dispute with Tartan involving a revenue sharing-arrangement for the storage and sale of crude oil.  Management is working to resolve the dispute amicably; however, the potential outcome is unknown.  Management does not believe that the contract-related dispute will have a material adverse effect on our financial position, earnings, or cash flows.  However, there can be no assurance that management’s efforts will result in a manageable outcome.

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 and 12,693,514 shares of Common Stock outstanding at December 31, 2022 and 2021, respectively.  Affiliates controlled approximately 83% of the voting power of our Common Stock as of the filing date of this report.  See “Part I, Item 1A. Risk Factors” for risks associated with investments in our Common Stock.

Stockholders

We had 272 and 270 record holders at December 31, 2022 and 2021, respectively.  We had approximately 3,000 beneficial holders of our Common Stock at both December 31, 2022 and 2021.

Dividends

Shareholders 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 are in compliance with covenants in our secured loan agreements, we are current on all required debt payments, and we have received prior written concurrence from certain of our lenders.

Common Stock Issuances

Set forth below is information regarding the issuance of Common Stock by us for the twelve months ended December 31, 2022 and 2021:

Services.

Payment of Debt.

The issuance of these securities were exempt from registration under the Securities Act in reliance on Section 4(a)(2) of the Securities Act.

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 years ended December 31, 2022 and 2021 and comparison between such periods. The discussions of the year ended December 31, 2020 and year-to-year comparisons between the years ended December 31, 2021 and 2020 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 fiscal year ended December 31, 2021, which was filed on April 1, 2022, and such discussions are incorporated by reference into this report.

Overview and Outlook

Company Overview.  Blue Dolphin is an independent downstream energy company operating in the Gulf Coast region of the United States.  Our subsidiaries operate a light sweet-crude, 15,000-bpd crude distillation tower with more than 1.2 million bbls of petroleum storage tank capacity in Nixon, Texas.  Our assets are primarily organized in two segments: refinery operations (owned by LE) and tolling and terminaling services (owned by LRM and NPS).  Subsidiaries that are reflected in corporate and other include BDPL (inactive pipeline assets), BDPC (inactive leasehold interests in oil and gas wells), and BDSC (administrative services). Blue Dolphin was formed in 1986 as a Delaware corporation and is traded on the OTCQX under the ticker symbol “BDCO”.

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

Going Concern.  In accordance with GAAP accounting standards, we evaluated whether there are conditions and events, considered in the aggregate, that raise substantial doubt about our ability to continue as a going concern within one year after the date that our consolidated financial statements are issued.  While results of operations were significantly improved for the twelve months ended December 31, 2022 versus the prior twelve month period, management determined that certain factors continue to present substantial doubt about our ability to continue as a going concern. Factors include significant current debt, which impacts our ability to meet debt covenants, and historical net losses and working capital and equity deficits. Our consolidated financial statements assume we will continue as a going concern and do not include any adjustments that might result from this uncertainty. Management is working to alleviate these factors by entering into forbearance agreements with lenders, maximizing operation of the Nixon refinery given favorable refining margins, and pursuing opportunities to obtain capital and/or refinance debt. Our ability to continue as a going concern depends on sustained positive operating margins and adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on long-term debt.  If we are unable to process crude oil and condensate into sellable refined products or make required debt payments, we may consider other options.  These options could include selling assets, raising additional debt or equity capital, cutting costs, reducing cash requirements, restructuring debt obligations, or filing a petition for bankruptcy.

Business Operations Update.  Our results for the year ended December 31, 2022 were favorably impacted by the ongoing recovery in the worldwide demand for petroleum-based transportation fuels, particularly jet fuel, while the worldwide supply of those products remained constrained. This supply and demand imbalance contributed to increases in the market prices of petroleum-based transportation fuels (as well as crude oil and other feedstocks that are processed to make these products) and thus in refining margins. Supply has remained constrained for a variety of reasons, including, but not limited to, effects from refinery closures and disruptions in the crude oil and petroleum-based products markets resulting from the Russian-Ukrainian military conflict. Some refineries closed over the past two years and other refineries ceased crude oil processing in favor of transitioning to renewable fuel production. In addition, these negative impacts to the supply of petroleum-based products were exacerbated during the second quarter of 2022 by the Russian-Ukrainian military conflict.  Due to the conflict, countries and private market participants responded by refraining from purchasing and transporting Russian crude oil and petroleum-based products; however, some of the uncertainties and related impacts began dissipating during the second half of 2022.

The strong demand for our products, particularly jet fuel, and the increase in refining margins were the primary contributors to us reporting $32.9 million in net income for the twelve months ended December 31, 2022. Our operating results for 2022, including operating results by segment, can be found within this “Management’s Discussion and Financial Analysis of Financial Condition and Results of Operations” within ‘Results of Operations.’

Our operations generated $16.3 million in cash for the twelve months ended December 31, 2022. We used cash from operations to pay $7.0 million to Veritex and GNCU, our largest lenders, during the same period  [as described in “Part II, Item 8. Financial Statements and Supplementary Data – Note (10)”] and made $0.1 million in capital improvements to the Nixon facility.  At December 31, 2022, we had $0.5 million in liquidity. 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 this “Management’s Discussion and Financial Analysis of Financial Condition and Results of Operations” within ‘Liquidity and Capital Resources.’

General Trends and Outlook.  The economic effects from the COVID-19 pandemic on our business were and may again be significant. Although our business has recovered since the onset of the pandemic in March 2020, there continues to be uncertainty and unpredictability about the lingering impacts of COVID-19 to the worldwide economy, including in connection with the spread of variants and resulting restrictions, that could negatively affect our business, financial condition, results of operations , and liquidity in future periods.  Additionally, many uncertainties remain with respect to the supply and demand imbalance in the petroleum-based products market worldwide due to the Russian-Ukrainian military conflict and a global economic recession. While it is difficult to predict the ultimate economic impacts of COVID-19, the Russian-Ukrainian military conflict, recession, and inflation may have on us, we have noted key factors below that impacted our results of operations in 2022 and will likely impact our results of operations during 2023:

Liquidity and Access to Capital Markets.  We continue to actively explore additional financing to meet working capital needs or refinance and restructure debt. During the twelve months ended December 31, 2022 and 2021, we secured $1.5 million and $10.5 million, respectively, in working capital from CARES Act loans. There can be no assurance that we will be able to raise additional capital on acceptable terms, or at all, or refinance existing debt. If we are unable to raise sufficient additional capital, we may not, in the short term, be able to purchase crude oil and condensate or meet debt payment obligations. In the long term, we may not be able to withstand business disruptions, such as those related to COVID-19, or execute our business strategy. We may have to consider other options, such as selling assets, raising additional debt or equity capital, seeking bankruptcy protection, or ceasing operations.

Changes in Regulations. Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local, and other laws and regulations that are increasing in number and becoming more stringent and complex. These laws and regulations include, among other things, permitting requirements, environmental protection measures such as limitations on methane and other 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.

Business Strategy and Accomplishments

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

Optimize Existing Asset Base.  Given continued favorable refining margins, we delayed performing the Nixon facility’s maintenance turnaround until the second quarter of 2023 in order to maximize refinery runs. Although the refinery experienced a similar amount of downtime during the twelve months ended December 31, 2022 (22 days) compared to the twelve months ended December 31, 2021 (23 days), we experienced fewer days of crude deficiencies associated with cash constraints during the 2022 period. During 2022, we focused on improvements in day-to-day plant operations, identifying safety and mechanical process improvements to optimize plant operations.

Improve Operational Efficiencies.  We carefully managed product mix, product inventory levels, and crude acquisition to maintain improvements to refinery throughput, production, and sales during the twelve months ended December 31, 2022 compared to the same period in 2021.  Refinery charge and production capacity utilization rates improved more than 5% each to 87.7% and 85.5%, respectively, during the twelve months ended December 31, 2022 from 81.8% and 79.8%, respectively, during the twelve months ended December 30, 2021.

Seize Market Opportunities. As a result of higher commodity prices and increased capacity utilization rates, we experienced a significant improvement in gross profits. Gross profit totaled $46.1 million for the twelve months ended December 31, 2022 compared to $0.9 million for the twelve months ended December 31, 2021.

In 2021, we announced plans to leverage our existing infrastructure to establish adjacent lines of business, capture growing market opportunities, and capitalize on green energy growth. Rising demand for green energy is attributable to a variety of factors, including growing public support, U.S. governmental actions to increase energy independence, and environmental concerns related to climate change.  Our initial focus includes commercialization opportunities in hydrogen, carbon capture and storage, carbon offsets and emerging technologies. During the twelve months ended December 31, 2022, management had discussions with several potential commercial partners and explored project-based opportunities through government loans as vehicles to enter the renewable energy space. Management expects these efforts to continue in 2023. As discussed throughout this report, our ‘going concern’ opinion may impact our renewable energy endeavors. Furthermore, reductions or modifications to, or the elimination of, governmental incentives or policies that support renewable energy or the imposition of additional taxes, tariffs, duties, or other assessments on renewable energy projects, could result in, among other things, the lack of a satisfactory market for the development and/or financing of new renewable energy projects and us abandoning the development of renewable energy projects.

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

Downstream Operations

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

Crude Oil and Condensate Supply.  Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. We have a long-term crude supply agreement in place with Tartan.  The volume-based Crude Supply Agreement expires when we receive 24.8 million net bbls of crude oil.  After that, the Crude Supply Agreement automatically renews for successive one-year terms (each such term, a renewal term).  Tartan must provide notice of non-renewal at least 60 days before the expiration of any renewal term.  For the twelve months ended December 31, 2022 and 2021, we received approximately 4.5 million bbls, or 18.4%, and 4.2 million bbls, or 17.0%, respectively, of the contracted volume under the Crude Supply Agreement.  As of December 31, 2022, we received approximately 13.6 million bbls, or 54.8%, of the total allowable contracted volume under the Crude Supply Agreement. At December 31, 2022, accounts payable for crude oil and condensate was $0. As of December 31, 2022, 100% of our crude oil was sourced from Tartan under the Crude Supply Agreement.

Related to the Crude Supply Agreement, Tartan stores crude oil at the Nixon facility under a terminal services agreement dated as of June 1, 2019.  Under the terminal services agreement, crude oil is stored at the Nixon facility at a specified rate per bbl of the storage tank’s shell capacity.  The terminal services agreement renews on a one-year evergreen basis.  Tartan must provide notice of non-renewal at least 60 days before the expiration of any renewal term.  However, the terminal services agreement will automatically terminate upon expiration or termination of the Crude Supply Agreement.

Our financial health has been materially and adversely affected by defaults in our secured loan agreements, significant current debt, margin volatility, historical net losses and working capital and equity deficits.  If Tartan terminates the Crude Supply Agreement or terminal services agreement, our ability to acquire crude oil and condensate could be adversely affected. 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.

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

The Nixon refinery’s product slate is adjusted based on market demand. We currently produce a single finished product – jet fuel – and several intermediate products, including naphtha, HOBM, and AGO.  Our jet fuel is sold to an Affiliate, which is HUBZone certified.  The product sales agreement with the Affiliate has a one-year term expiring the earliest to occur of March 31, 2024 plus 30-day carryover or delivery of the maximum quantity of jet fuel.  Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing.

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

Competition.  Many 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.  Most of our storage tanks are equipped with leak detection devices. We also have response and control plans in place for spill prevention and emergencies.

The Nixon refinery periodically undergoes planned and unplanned temporary shutdowns. We typically complete a planned turnaround annually to repair, restore, refurbish, or replace refinery equipment. However, the timing of planned turnarounds is adjusted to capitalize on favorable market conditions. Occasionally, unplanned shutdowns occur.  Unplanned downtime can occur for a variety of reasons; however, common reasons for unplanned downtime include repair/replacement of disabled equipment, crude deficiencies associated with cash constraints, high temperatures, and power outages.  In 2021, the Nixon refinery did not incur significant damage due to Winter Storm Uri; however, the facility lost external power for 10 days due to the storm. In December 2022, the Nixon refinery was idled for 5 days due to an unnamed winter ice storm.

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

Midstream Operations

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

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

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

Inactive Operations

We own other pipeline and facilities assets and have leasehold interests in oil and gas properties.  These assets are inactive.  We account for these inactive operations in ‘corporate and other.’  Our pipeline assets have been fully impaired since 2016 and our oil and gas leasehold interests have been fully impaired since 2011. Our pipeline assets and oil and gas leasehold interests had no revenue during the twelve months ended December 31, 2022 and 2021.  See “Part II, Item 8. Financial Statements and Supplementary Data – Note (15)” related to pipelines and platform decommissioning requirements and related risks.

Pipeline and Facilities Safety. 

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

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Results of Operations

A discussion and analysis of the factors contributing to our consolidated financial results of operations is presented below and should be read in conjunction with our financial statements in “Part I, Item 1. Financial Statements”. The financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but they should not serve as the only criteria for predicting future performance.

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

While refining margins improved significantly during 2022 primarily due to increased commodity prices and demand, the general outlook for the oil and natural gas industry for 2023 remains unclear given uncertainty surrounding the Russian military conflict with Ukraine, recession, inflation, and COVID-19. We can provide no assurances that refining margins and demand will remain at current levels.

How We Evaluate Our Operations.  Management uses certain financial and operating measures to analyze segment performance. These measures are significant factors in assessing our operating results and profitability and include: segment contribution margin (deficit), and refining gross profit (deficit) per bbl, storage tank rental revenue, operation costs and expenses, refinery throughput and production data, and refinery downtime. Segment contribution margin (deficit) and refining gross profit (deficit) per bbl are non-GAAP measures.

Segment Contribution Margin (Deficit) and Refining Gross Profit (Deficit) per Bbl

We use segment contribution margin (deficit) to evaluate the performance of our downstream and midstream operations.  We use refining gross profit (deficit) per bbl as a downstream benchmark. Both measures supplement GAAP financial information presented. Management uses segment contribution margin (deficit) and refining gross profit (deficit) per bbl to analyze our results of operations, assess internal performance against budgeted and forecasted amounts, and evaluate impacts to our financial performance considering potential capital investments.  These non-GAAP measures have important limitations as analytical tools. They should not be considered a substitute for GAAP financial measures. We believe these measures may help investors, analysts, lenders, and ratings agencies analyze our results of operations and liquidity in conjunction with our GAAP financial results. See “Non-GAAP Reconciliations” for a reconciliation of Non-GAAP measures to U.S. GAAP.

Storage Tank Rental Revenue and Ancillary Services Fees

Tolling and terminaling revenue primarily represents storage tank rental fees and ancillary services fees associated with customer tank rental agreements. As a result, tank rental revenue and ancillary services fees combined are one of the measures management uses to evaluate the performance of our tolling and terminaling business segment.

Operation Costs and Expenses

We manage operating costs and expenses in tandem with meeting environmental and safety requirements and objectives and maintaining the integrity of our assets.  Operating costs and expenses are comprised primarily of labor expenses, repairs and other maintenance costs, and utility costs. Expenses for refinery operations generally remain stable across broad ranges of throughput volumes, but they can fluctuate from period to period depending on the mix of activities performed during that period and the timing of those expenses.  Operation costs and expenses for tolling and terminaling operations are relatively fixed.

Refinery Throughput and Production Data

The amount of revenue we generate from the refinery operations business segment primarily depends on the volumes of crude oil that  we process into refined products and the volume of refined products sold to customers.  These volumes are affected by the supply and demand of, and demand for, crude oil and refined products in the markets served directly or indirectly by our assets, as well as refinery downtime.

Refinery Downtime

The Nixon refinery periodically experiences planned and unplanned temporary shutdowns. Any scheduled or unscheduled downtime will result in lost margin opportunity, potential increased maintenance expense, and a reduction of refined products inventory, which could reduce our ability to meet our payment obligations.

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

Twelve Months Ended December 31, 2022 (“2022”) Versus December 31, 2021 (“2021”)

Overview.  Net income for 2022 was $32.9 million, or income of $2.34 per share, compared to a net loss of $12.8 million, or a loss of $1.01 per share, in 2021. The $45.7 million, or $3.35 per share, increase in net income between the periods was the result of favorable refining margins and improved product demand. The net loss in 2021 was also due to lower refinery margins, 23 days of refinery downtime; of the 23 days, 13 days related to crude deficiencies associated with cash constraints and 10 days were associated with Winter Storm Uri.  Although 2022 refinery downtime totaled 22 days (5 of which related to an unnamed winter ice storm), margins were higher.

Total Revenue from Operations.  Total revenue from operations increased 62% to $487.5 million for 2022 from $300.8 million for 2021. Increased commodity prices primarily drove refinery operations revenue higher in 2022; however, higher volume sales also contributed to the increase. Tolling and terminaling revenue increased nearly 20% between the periods to $4.4 million.

Total Cost of Goods Sold.  Total cost of goods sold increased approximately 47% to $441.4 million for 2022 from $299.9 million for 2021.  The significant increase related to higher crude acquisition costs and higher throughput.

Gross Profit.  Gross profit totaled $46.1 million for 2022 compared to gross profit of $0.9 million for 2021. Higher commodity prices and improved refinery uptime positively impacted refinery margins in 2022 compared to 2021.

General and Administrative Expenses. General and administrative expenses decreased $0.1 million, or nearly 4%, from $3.0 million in 2021 to $2.9 million in 2022. The decrease primarily related to lower legal fees.

Depreciation and Amortization.  Depreciation and amortization expenses remained flat at $2.8 million for both 2022 and 2021.

Total Other Income (Expense).  Total other expense in 2022 totaled $5.9 million compared to total other expense of $6.2 million in 2021, representing a decrease of approximately $0.3 million. The decrease was due to lower related party interest expense in 2022 compared to 2021.  Total other expense primarily relates to interest expense associated with third-party and related party secured loan agreements.

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.

2022 Versus 2021

Refinery Downtime. Refinery downtime decreased from 23 days in 2021 to 22 days in 2022.  Refinery downtime in 2021 related to crude deficiencies associated with cash constraints (13 days) and downtime associated with Winter Storm Uri (10 days). Refinery downtime in 2022 related to maintenance (13 days), weather associated with an unnamed ice storm (5 days), and crude deficiencies associated with cash constraints (4 days).

Refining Gross Profit (Deficit).  Refining gross profit was $41.6 million for 2022 compared to gross deficit of $2.8 million in 2021, representing a significant increase of $44.4 million. The significant increase in 2022 related to higher refining margins, improved product demand, and improved throughput. Refining gross deficit in 2021 was the result of lower margins and COVID-19 market fluctuations.

Refining Gross Profit (Deficit) per Bbl. On a per bbl basis, refining gross profit was $9.78 for 2022 compared to a gross deficit of $0.69 for 2021, representing a significant increase of $10.47 per bbl.  The increase related to favorable commodity prices and increased refined product demand.

Segment Contribution Margin (Deficit). Refinery operations segment contribution margin improved $44.6 million from a deficit of $3.4 million in 2021 to $41.2 million in 2022 due to higher refining margins.

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

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

2022 Versus 2021

Tolling and Terminaling Revenue. Storage tank rental and ancillary services fees increased $0.7 million from $3.7 million in 2021 to $4.4 million in 2022. Intercompany processing fees increased 5% from $2.5 million in 2021 to $2.6 million in 2022. Processed naphtha volumes increased nearly 34% between the two periods.

Segment Contribution Margin. Tolling and terminaling segment contribution margin increased 12% from $4.3 million in 2021 to $4.9 million in 2022. The increase related to higher tank rental and ancillary service fees and slightly higher operation costs and expenses. 

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

Non-GAAP Reconciliations.

Reconciliation of Segment Contribution Margin (Deficit)

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

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Capital Resources and Liquidity

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. Profitability from favorable refining margins and increased product demand in 2022 improved cash flow from operations. Continued liquidity improvement related to favorable market conditions will enable us to increasingly meet our needs through cash flow from operations. 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 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.

During 2022 and 2021, we successfully secured an additional $1.5 million and $10.5 million, respectively, in working capital through CARES Act loans. In October 2021, NPS repaid all obligations owed to Pilot under the Amended Pilot Line of Credit.  We also continue to actively explore additional financing to meet working capital needs or 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, the Russian military conflict with Ukraine, COVID-19, recession, and inflation continue to evolve, and the extent to which these factors may impact our business, financial condition, liquidity, results of operations, and future prospects will depend on future developments, which cannot be predicted with any degree of confidence.

If refining margins become unfavorable for an extended period, reducing available working capital, and we are unable to raise additional capital, 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 operating.

Working Capital

We had $45.2 million and $78.5 million in working capital deficits at December 31, 2022 and 2021, respectively.  Excluding the current portion of long-term debt, we had $2.1 million in working capital and $15.5 million in working capital deficits at December 31, 2022 and 2021, respectively. The significant improvement in working capital between the twelve-month periods was primarily due to favorable refining margins and increased gross profit. During the twelve months ended December 31, 2022, continued liquidity improvement related to favorable market conditions enabled us to increasingly meet our needs through cash flow from operations.

Cash and cash equivalents totaled $0.5 million and $0.01 million at December 31, 2022 and 2021, respectively.  Restricted cash (current portion) totaled $0 and $0.05 million at December 31, 2022 and 2021, respectively. Restricted cash, noncurrent totaled $1.0 million and $0 at December 31, 2022 and 2021, respectively. 

Sources and Use of Cash

Components of Cash Flows

Cash Flow from Operations

We had cash flow from operations of $16.3 million for 2022 compared to a cash flow deficit from operations of $6.1 million for 2021. The $22.3 million improvement in cash flow from operations between the periods was due to profit from operations, which was offset by a buildup in inventory.

Capital Expenditures

Capital expenditures totaled $0.1 million and $0 in 2022 and 2021, respectively. Capital expenditures in 2022 related to the addition of a portable cooling tower to combat increased summer temperatures and new fire equipment. Due to continued uncertainties surrounding commodity pricing and refined product demand, the Russian military conflict with Ukraine, recession, inflation, and COVID-19, we anticipate limited capital expenditures over the next twelve months. However, to the extent we are able to capitalize on green energy growth opportunities, we may finance capital expenditures through project-based government loans.

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

Debt Activities

Net proceeds from the issuance of debt totaled $1.5 million and $10.5 million in 2022 and 2021, respectively. Proceeds in 2022 represented additional principal under the BDEC Term Loan Due 2051; proceeds in 2021 reflected the original principal under the NPS Term Loan Due 2031.

A summary of payment activities to third parties and related parties follow:

Third-Party

Related-Party

Total Debt and Lease Obligations

The table below summarizes our principal contractual debt and lease obligations at December 31, 2022, by expected settlement period.

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

One of our significant customers is LEH, an Affiliate. Due to a HUBZone certification, the Affiliate purchases our jet fuel under a Jet Fuel Sales Agreement and bids on jet fuel contracts under preferential pricing terms.  For the twelve months ended December 31, 2022 and 2021, the Affiliate accounted for approximately 35.6% and 29.9% of total revenue from operations, respectively.

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

BOEM Additional Financial Assurance (Supplemental Pipeline Bonds)

To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to conduct 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.

BDPL historically maintained $0.9 million in financial assurance to BOEM for the decommissioning of its trunk pipeline offshore in federal waters.  Following an agency restructuring of the financial assurance program, in March 2018 BOEM ordered BDPL to provide additional financial assurance totaling approximately $4.8 million for five (5) existing pipeline rights-of-way.  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 milestones identified in an August 2019 meeting between management and BSEE may help in future discussions with BOEM related to the INCs. Decommissioning of these assets will significantly reduce or eliminate the amount of financial assurance 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 financial assurance (supplemental pipeline bond) requirements. If BDPL is required by BOEM to provide significant additional financial assurance (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 are currently unable to predict the outcome of the BOEM INCs.  Accordingly, we did not record a liability on our consolidated balance sheets as of December 31, 2022 and 2021.  At both December 31, 2022 and 2021, BDPL maintained approximately $0.9 million in pipeline rights-of-way surety bonds issued to BOEM through RLI Corp.  Of the pipeline rights-of-way bonds, $0.7 million was credit-backed and $0.2 million was cash-backed.

BSEE Offshore Pipelines and Platform Decommissioning

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

In December 2018, BSEE issued an INC to BDPL for failing to flush and fill Pipeline Segment No. 13101.  Management met with BSEE in August 2019 to address BDPL’s plans with respect to decommissioning its offshore pipelines and platform assets.  BSEE proposed that BDPL re-submit pipeline and platform decommissioning permit applications, including a safe boarding plan, by February 2020.  BDPL submitted permit applications to BSEE in February 2020 and the USACOE in March 2020.  In April 2020, BSEE issued another INC to BDPL for failing to perform the required structural surveys for the GA-288C Platform. BDPL completed the required platform surveys in June 2020. 

In August 2022, BSEE issued an INC to BDPL for failing to complete decommissioning its main offshore pipeline and anchor platform. In addition, pursuant to a September 2022 letter, BSEE ordered BDPL to complete pipeline decommissioning and removal of the anchor platform by June 1, 2023.  BDPL is examining the feasibility of completing decommissioning operations by BSEE’s deadline. In March 2023, BSEE issued an INC to BDPL for failing to perform the required structural surveys for the GA-288C platform for 2021 and 2022, and for failing to provide BSEE with such survey results.  BDPL is obtaining vendor quotes for the performance of the required surveys and intends to submit a corrective action plan to BSEE.  If BDPL fails to complete decommissioning of the offshore pipeline and platform assets and/or remedy the INCs within the timeframe mandated by BSEE, BDPL could be subject to regulatory oversight and enforcement, including but not limited to failing to correct an INC, civil penalties, and revocation of BDPL’s operator designation, which could have a material adverse effect on our earnings, cash flows, and liquidity. 

We cannot currently estimate when decommissioning may occur or predict the outcome of the BSEE INCs.  Accordingly, we did not record a liability related to potential penalties on our consolidated balance sheets as of December 31, 2022 and 2021.  At December 31, 2022 and 2021, BDPL maintained $3.7 million and $3.5 million, respectively, in AROs related to abandonment of these assets, which amount does not include potential penalties.

Off-Balance Sheet Arrangements.  None.

Accounting Standards.

Critical Accounting Policies and Estimates

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

Estimates. The nature of our business requires that we make estimates and assumptions in accordance with U.S. GAAP.  These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenue and expenses during the reporting period. Although commodity price volatility, the Russian-Ukrainian military conflict, COVID-19, recession, inflation, and severe weather resulting from climate change have impacted these estimates and assumptions, we are continually working to mitigate future risks. However, the extent to which these factors may impact our business, financial condition, liquidity, results of operations, and future prospects will depend on future developments, which cannot be predicted with any degree of certainty.

We assessed certain accounting matters that require consideration of forecasted financial information in context with information reasonably available to us as of December 31, 2022 and through the filing date of this report.  The accounting matters assessed included, but not limited to, our allowance for doubtful accounts, inventory, and related reserves, and the carrying value of long-lived assets.

New Accounting Standards and Disclosures

New Pronouncements Adopted. During the twelve months ended December 31, 2022, we did not adopt any ASUs.

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of Blue Dolphin Energy Company

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and Subsidiaries (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”).  In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Substantial Doubt about the Company’s Ability to Continue as a Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note (1) to the consolidated financial statements, the Company is in default under secured and related party loan agreements and has a net working capital deficiency.  These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management's plans in regard to these matters are also described in Note (1). The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. 

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits.  We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.  Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.  Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Related Party Transactions

As described in Note 3 to the consolidated financial statements, Lazarus Energy Holdings (LEH) is a controlling stockholder of Blue Dolphin Energy Company.  In addition, there is an overlapping director and executive officer between the companies.  Each of these entities has been identified as a related party at December 31, 2022.  The Company has entered into a number of transactions with related parties, including but not limited to, agreements for management of the operating facility, sale of jet fuel, and various credit facilities.

We identified the evaluation of the Company’s identification of related parties and related party transactions as a critical audit matter.  This required a high degree of auditor judgment and subjectivity in performing procedures to evaluate the reasonableness of management’s procedures performed to identify related parties and related party transactions.

Our audit procedures included, among others (i) inquiring of executive officers, key members of management, the Audit Committee of the Board of Directors, and others within the Company regarding related party relationships and transactions, (ii) receiving confirmations from related parties and compared responses to the Company’s records, (iii) comparing the Company’s reconciliation of applicable accounts to related parties’ records of transactions and balances, (iv) reading agreements and contracts with related parties and evaluated whether authorization and approvals were obtained and the terms and other information about transactions are consistent with explanations from inquiries and other audit evidence obtained about the business purpose of the transactions, (v) reading the Company’s minutes from meetings of the Board of Directors, and (vi) evaluating the completeness and accuracy of disclosures surrounding related party transactions.

PCAOB Number: 01195 

We have served as the Company’s auditor since 2002.

Consolidated Balance Sheets