BLUE DOLPHIN ENERGY CO - Annual Report: 2018 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

 

FORM 10-K

(Mark One)

[ √ ]

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2018

 or

 

[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from             to           

 

Commission File No. 0-15905

 

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

 

Delaware		73-1268729
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
801 Travis Street, Suite 2100, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)
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:

 

Common Stock, par value $0.01 per share

(Title of class)

 

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes [ √ ] No [ ]

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ √ ]

 

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 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 $4,000,124 as of June 29, 2018 (the last business 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 29, 2018.

 

Number of shares of common stock, par value $0.01 per share, outstanding at April 1, 2019: 10,975,514

 

 

 

TABLE OF CONTENTS

 

GLOSSARY OF SELECTED ENERGY, FINANCIAL, AND OTHER TERMS		4
PART I		6
ITEM 1.	BUSINESS	6
ITEM 1A.	RISK FACTORS	16
ITEM 1B.	UNRESOLVED STAFF COMMENTS	28
ITEM 2.	PROPERTIES	29
ITEM 3.	LEGAL PROCEEDINGS	30
ITEM 4.	MINE SAFETY DISCLOSURES	30
PART II		31
ITEM 5.	MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	31
ITEM 6.	SELECTED FINANCIAL DATA	31
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	45
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	79
ITEM 9A.	CONTROLS AND PROCEDURES	79
ITEM 9B.	OTHER INFORMATION	80
PART III		81
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	81
ITEM 11.	EXECUTIVE COMPENSATION	86
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	88
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	89
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	89
PART IV		90
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	90
ITEM 16.	FORM 10-K SUMMARY	90
SIGNATURES		98

 

INTRODUCTION

 

This Annual Report for the fiscal year ended December 31, 2018 (this “Annual Report”) is a document that U.S. public companies file with the Securities and Exchange Commission (“SEC”) every year. Part I of this Annual Report provides a general overview of our business, including relevant risk factors. Part II of this Annual Report contains financial information and management’s discussion and analysis of our financial condition and results of operations. Part III provides information with respect to executive and director compensation. We hope investors will find it useful to have all this information in a single document.

 

In this Annual Report, “Blue Dolphin,” “we,” “our,” and “us” are used interchangeably to refer to Blue Dolphin Energy Company individually or to Blue Dolphin Energy Company and its subsidiaries collectively, as appropriate to the context. Information in this Annual Report is current as of the filing date, unless otherwise specified.

 

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

 

In this Annual Report, and from time to time throughout the year, we share our expectations for our future performance. These forward-looking statements include statements about our business strategy; our expected financial performance, including the anticipated effect of strategic actions; economic, political and market conditions; and other factors that could affect our future results of operations or financial condition, including, without limitation, statements under the sections entitled “Part I, Item 1. Business,” “Part I, Item 1A. Risk Factors,” “Part I, Item 3. Legal Proceedings,” and “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Any statements we make that are not matters of current reportage or historical fact should be considered forward-looking. Such statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “will,” and similar expressions. By their nature, these types of statements are uncertain and are not guarantees of our future performance. Our forward-looking statements represent our estimates and expectations at the time of disclosure. However, circumstances change constantly, often unpredictably, and investors should not place undue reliance on these statements. Many events beyond our control will determine whether our expectations will be realized. We disclaim any current intention or obligation to revise or update any forward-looking statements, or the factors that may affect their realization, whether considering new information, future events or otherwise, and investors should not rely on us to do so. In accordance with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, “Part I, Item 1A. Risk Factors” in this Annual Report explains some of the important factors that may cause actual results to be materially different from those that we anticipate.

 

 

 

 

 

 

 

 

 

Remainder of Page Intentionally Left Blank

 

 

GLOSSARY OF SELECTED ENERGY, FINANCIAL, AND OTHER TERMS

 

Below are abbreviations and definitions of certain commonly used oil and gas industry terms, as well as key financial performance measures used by management, that are used in this Annual Report.

 

Regarding financial terms, management uses U.S. generally accepted accounting principles (“GAAP”) and certain non-GAAP performance measures to assess our results of operations. Certain performance measures used by management to assess our operating results and the effectiveness of our business segment are considered non-GAAP performance measures. These performance measures may differ from similar calculations used by other companies within the petroleum industry, thereby limiting their usefulness as a comparative measure. We refer to certain refinery throughput and production data in the explanation of our period over period changes in results of operations. For our consolidated results, we refer to our consolidated statements of operations in the explanation of our period over period changes in results of operations.

 

PART I

 

Company Overview

 

Blue Dolphin Energy Company is a publicly-traded Delaware corporation formed in 1986, that is primarily engaged in the refining and marketing of petroleum products. We also provide tolling and storage terminaling services. Our assets, which are in Nixon, Texas, primarily include a 15,000-bpd crude distillation tower and approximately 1.1 million bbls of petroleum storage tank capacity (collectively the “Nixon Facility”). Pipeline transportation and oil and gas operations are no longer active. Blue Dolphin maintains a website at http://www.blue-dolphin-energy.com. Information on or accessible through Blue Dolphin’s website is not incorporated by reference in or otherwise made a part of this Annual Report.

 

Structure and Management

 

Corporate Structure

 

Blue Dolphin has two (2) business segments – Refinery Operations and Tolling and Terminaling, both of which are conducted at the Nixon Facility through the below active subsidiaries:

 

Refinery Operations

 

 

Tolling and Terminaling

 

 

 

In June 2018, Blue Dolphin acquired 100% of the issued and outstanding membership interests of NPS from Lazarus Midstream Partners, L.P., an affiliate of Lazarus Energy Holdings, LLC (“LEH”), pursuant to an Assignment Agreement. The transaction represents transfer of a vacant shell entity for the nominal fee of $10.00. The assignment was accounted for as a combination of entities under common control. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (5) NPS Assignment” of this Annual Report for further information related to the NPS assignment.)

 

Blue Dolphin also owns pipeline assets and has leasehold interests in oil and gas wells. These assets and wells, which are not operational, are included in Corporate and Other. Corporate and Other includes the below active subsidiaries:

 

 

 

See "Part I, Item 2. Properties” for additional information regarding our operating subsidiaries, facilities, and assets.

 

 

Management

 

Blue Dolphin is controlled by LEH. LEH operates and manages all Blue Dolphin properties pursuant to an Amended and Restated Operating Agreement (the “Amended and Restated Operating Agreement”). Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, as well as a majority owner of LEH. Together LEH and Jonathan Carroll owned 79.8% of our common stock, par value $0.01 per share (the “Common Stock) at December 31, 2018. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (9) Related-Party Transactions, Note (11) Long-Term Debt, Net and Note (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Amended and Restated Operating Agreement, and Jonathan Carroll.)

 

Going Concern

 

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Going Concern” regarding factors that management has determined raise substantial doubt about our ability to continue as a going concern.

 

Operating Risks

 

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Operating Risks” regarding factors that management has determined represent operating risks.

Business Strategy

 

Management has determined that there is substantial doubt about our ability to continue as a going concern due to consecutive net losses, inadequate working capital, the Final Arbitration Award, and defaults under secured loan agreements. In 2018, our focus was on improving our financial stability and increasing utilization of existing assets while controlling costs, operating safely, and using environmentally appropriate operating practices. Management believes that it is continuing to take the appropriate steps. Actions to date include:

 

 

 

Successful execution of our business strategy depends on several key factors, including Settlement with GEL, having adequate working capital, obtaining credit to meet operational and regulatory requirements, maintaining safe and reliable operations at the Nixon Facility, meeting contractual obligations, and having favorable margins on refined petroleum products. Our results of operations and liquidity are highly dependent upon the margins that we receive for our refined petroleum products. The dollar per bbl price difference between crude oil and condensate (input) and refined petroleum products (output) is the most significant driver of refining margins, and they have historically been subject to wide fluctuations.

 

 

There can be no assurance that our strategy will be successful, that LEH and its affiliates will continue to fund our working capital needs, that we will be able to obtain additional financing on commercially reasonable terms or at all, or that margins for refined petroleum products will be favorable. Veritex Community Bank (“Veritex”), as first lien holder in secured loan agreements, has been working with LE and LRM and continues to be aware and party to all discussions and arrangements with GEL surrounding the Settlement. However, if Veritex does not approve the Settlement or exercises its rights and remedies under secured loan agreements or the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin would likely be required to seek protection under bankruptcy laws.

 

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Going Concern” for additional disclosures related to the Final Arbitration Award, the Settlement Agreement with GEL (as amended), defaults under secured loan agreements, as well as certain factors: (i) that raise substantial doubt about our ability to continue as a going concern and (ii) that management has determined represent operating risks.

 

Nixon Facility

 

The Nixon Facility is comprised of assets owned by LE and LRM. LE owns the land, crude oil distillation unit, certain refined petroleum product storage tanks and related piping, and loading and unloading facilities and utilities. LRM owns the naphtha stabilizer and depropanizer units, as well as certain petroleum product storage tanks and related piping. NPS subleases certain petroleum storage tanks from LE.

 

In 2015, LE and LRM secured $35.0 million in the aggregate in USDA-guaranteed 19-year financing to expand the Nixon Facility’s petroleum storage tank farm. Increased petroleum storage capacity: (i) assists with de-bottlenecking the facility, (ii) supports increased refinery throughput up to approximately 30,000 bpd, and (iii) provides an opportunity to generate additional tolling and terminaling revenue.

 

As of the date of this Annual Report, the refinery had approximately 1.1 million bbls of crude oil, condensate, and refined petroleum product storage capacity across 35 tanks. When the expansion project is complete, petroleum storage capacity at the Nixon Facility will exceed 1.2 million bbls, an increase of more than 0.9 million bbls since the project began in 2015. The Nixon Facility’s business assets are pledged as collateral under certain of our long-term debt. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (11) Long-Term Debt, Net” for additional disclosures related to borrowings for capital spending.

 

Refinery Operations

 

Refining Industry Overview

 

Crude oil refining is the process of separating the hydrocarbons present in crude oil into usable or refined petroleum products such as naphtha, diesel, jet fuel and other products. Crude oil refining is primarily a margin-based business where both crude oil and refined petroleum products are commodities with prices that can fluctuate independently for short periods due to supply, demand, transportation and other factors. To increase profitability, or improve margins, it is important for a crude oil refinery to maximize the yields of higher value petroleum products and to minimize the costs of feedstocks and operating expenses. There are also several operational efficiencies that can be deployed to improve margins. These include selecting the appropriate crude oil or condensate to fulfill anticipated product demand, increasing the amount and value of refined petroleum products processed from the crude oil or condensate, reducing downtime for maintenance, repair and investment, developing valuable by-products or production inputs out of materials that are typically discarded, and adjusting utilization rates.

 

A refinery's product slate depends on the refinery's configuration and the type of crude oil and/or condensate being refined and can be adjusted based on market demand. Although an increase or decrease in the price for crude oil generally results in a similar increase or decrease in prices for refined petroleum products, typically there is a time lag between the comparable increase or decrease in prices for refined petroleum products. The effect of changes in crude oil prices on a refinery’s results of operations depends, in part, on how quickly and how fully refined petroleum products prices adjust to reflect these changes.

 

 

 

Refinery Process Summary

 

The Nixon refinery is considered a “topping unit” because it is primarily comprised of a crude oil distillation tower or unit, the first stage of the crude oil refining process. The distillation process (crude distillation tower) separates crude oil and condensate into finished and intermediate petroleum products.

 

The below diagram represents a high-level overview of the current crude oil and condensate refining process at the Nixon refinery.

 

 

 

 

 

 

 Example represents a simplified plant configuration. The specific configuration will vary based on various market and operational factors.

 

The Nixon refinery is supported by a tank farm that provides feedstock and surge storage capacity, ensuring smooth, uninterrupted refinery operations. A regional electric cooperative supplies electrical power to the Nixon refinery. Fuel gas that is produced at the Nixon refinery is primarily used as fuel within the refinery. In addition, small amounts of propane are occasionally acquired for use in starting-up the Nixon refinery.

 

Safety and Reliability

 

We are committed to safe and efficient operations at the Nixon Facility. Turnarounds are used to repair, restore, refurbish or replace refinery equipment such as vessels, tanks, reactors, piping, rotating equipment, instrumentation, electrical equipment, heat exchangers and fired heaters. Typically, a refinery undergoes a major facility turnaround every three to five years. Since the Nixon refinery is still in the recommissioning phase, turnarounds and unscheduled downtime are needed more frequently for unanticipated maintenance or repairs.

 

 

Crude Oil and Condensate Supply

 

Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect the supplier to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, as well as other factors, including as net losses, working capital deficits, and financial covenant defaults in secured loan agreements.

 

Management believes that it is taking the appropriate steps to improve our operations and financial stability. If our business strategy is unsuccessful, it could affect our ability to acquire adequate supplies of crude oil and condensate under the existing contract or otherwise. Further, because our existing crude supply contract is a month-to-month arrangement, there can be no assurance that crude oil and condensate supplies will continue to be available under this contract in the future.

 

Products and Markets

 

Products. The Nixon refinery’s product slate can be moderately adjusted based on market demand. We currently produce a single finished product – jet fuel. We produce several intermediate products, including naphtha, HOBM, and AGO.

 

Markets. The Nixon refinery is in the Gulf Coast region of the U.S., which is represented by the Energy Information Administration as Petroleum Administration for Defense District 3 (“PADD 3”).  Our products are primarily sold in the U.S. within PADD 3. However, with the opening of the Mexican refined products market to private companies, we occasionally sell refined products to customers that export to Mexico. LEH, which is HUBZone certified, purchases our jet fuel and resells the jet fuel to a government agency. Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing. (See “Part I, Item 1. Business – Structure and Management” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (9) Related-Party Transactions, Note (11) Long-Term Debt, Net, and Note (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.)

 

Customers. Customers for our refined petroleum 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, including month-to-month, six months, and up to one-year terms, in place with most of our customers. 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, which could result in higher or lower relative prices for our refined petroleum products. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (15) Concentration of Risk” of this Annual Report for disclosures related to significant customers.

 

Competition. Many of our competitors are substantially larger than us and are engaged on a national or international basis in many segments of the petroleum products business, including exploration and production, refining, 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 petroleum products slate because of changing commodity prices, market demand, and refinery operating costs.

 

Tolling and Terminaling Operations

 

Operations Overview

 

We conduct tolling and terminaling operations at the Nixon Facility. The Nixon Facility has a tank farm providing approximately 1.1 million bbls of petroleum storage tank capacity, 0.7 million bbls of which is used for tolling and terminaling storage. Shipments are received and redelivered from within the Nixon Facility via pipeline or from third parties via truck.

 

 

Products and Customers

 

The Nixon Facility’s petroleum storage tanks and infrastructure are primarily suited for crude oil and condensate and refined petroleum products, such as naphtha, jet fuel, diesel and fuel oil. Storage customers are typically refiners primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). Contract terms range from month-to-month to three years.

 

Acquisition, Disposition and Restructuring Activities

 

We regularly engage in discussions with third parties regarding the possible purchase of assets and operations that are strategic and complementary to our existing operations. However, we do not anticipate any material acquisition activity in the foreseeable future.

 

Insurance and Risk Management

 

Our operations are subject to significant hazards and risks inherent in crude oil and condensate refining operations, as well as in the transportation and storage of crude oil and condensate and finished and intermediate petroleum products. We have property damage and business interruption coverage 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. Our property damage insurance has deductibles ranging from $5,000 to $500,000. In addition, we have a full suite of insurance policies covering workers’ compensation, general liability, directors’ and officers’ liability, environmental liability, and other business risks. These are supported by safety and other risk management programs. See also, “Part I, Item 1A. Risk Factors – Risks Related to Our Business” in this Annual Report.

 

Governmental Regulation

 

Our operations are subject to extensive and complex federal, state, and local environmental, health, and safety statutes, regulations, and ordinances. These laws govern, among other things, the generation, storage, handling, use and transportation of petroleum, solid wastes, hazardous wastes, and hazardous substances; the emission and discharge of materials into or through the environment; waste management; characteristics and composition of diesel and other fuels; the monitoring, reporting and control of greenhouse gas emissions; the financial assurance necessary to satisfy decommissioning obligations; and the management of pipeline safety. These laws impose costly obligations on our operations, including requiring the acquisition of permits and authorizations to conduct regulated activities, restricting the way regulated activities are conducted, limiting the quantities and types of materials that may be released into the environment, and requiring the monitoring of releases of materials into the environment.

 

Failure to comply with environmental, health or safety laws and our existing permits or other authorizations issued under such laws could result in fines, civil or criminal penalties or other sanctions, injunctive relief compelling the installation of additional controls, a revocation of administering our permits, and/or the shutdown of our facilities.

 

We cannot predict the extent to which additional environmental, health, and safety laws will be enacted in the future, or how existing or future laws will be interpreted with respect to our operations. Many environmental, health, and safety laws and regulations are becoming increasingly stringent. The cost of compliance with and governmental enforcement of environmental, health, and safety laws may increase in the future. We may be required to make significant capital expenditures or incur increased operating costs to achieve or sustain compliance with applicable environmental, health, and safety laws. This Governmental Regulation section should be read in conjunction with “Part I, Item 1A. Risk Factors” of this Annual Report, which discusses our expectations regarding future events based on currently available information.

 

 

Air Emissions

 

Toxic Air Pollutants. The federal Clean Air Act (the “CAA”) regulates air pollutants from stationary and mobile sources. Among other things, the law authorizes the Environmental Protection Agency (the “EPA”) to establish National Ambient Air Quality Standards to protect public health and public welfare and to regulate emissions of hazardous air pollutants. The CAA, as well as corresponding state laws and regulations regarding emissions of pollutants into the air, affect our crude oil and condensate processing operations and impact certain emissions sources located offshore. Under the CAA, facilities that emit volatile organic compounds (“VOCs”) or nitrogen oxides face increasingly stringent regulations.

 

Petroleum refineries are subject to the EPA’s National Standards for Hazardous Air Pollutants. These standards require petroleum refineries to meet emission standards reflecting the application of the maximum achievable control technology. The affected sources at petroleum refineries are defined to include all process vents, storage vessels, marine tank vessel loading operations, gasoline rack operations, equipment leaks, and wastewater treatment systems located at the refinery. To meet emission standards, we are required to obtain permits, as well as test, monitor, report, and implement control requirements.

 

Under the EPA’s Mobile Source Air Toxics regulations most refineries producing transportation fuels for highway use in the United States are required to produce at or below 15 ppm sulfur for “on-road” and “off-road” diesel and 30 ppm sulfur for gasoline. The EPA’s Tier 3 Standards similarly reduced motor vehicle emission requirements. The Nixon refinery does not produce gasoline, and the facility ceased production of nonroad, locomotive, and marine, a transportation-related diesel fuel product in 2014 – when the new regulations took effect.  Since 2014, the Nixon refinery has produced HOBM, a non-transportation lubricant blend product.  “Topping units,” like the Nixon refinery, typically lack a desulfurization process unit to lower sulfur content levels within the range required by the EPA’s sulfur control standards, and integration of such a desulfurization unit generally requires additional permitting and significant capital upgrades. We can produce and sell diesel with sulfur content levels above the EPA’s sulfur control standards: (i) in the U.S. as a feedstock to other refineries and blenders and (ii) to other countries as a finished petroleum product.

 

Greenhouse Gas Emissions. Emission of Greenhouse Gases (“GHGs”) is regulated by the EPA under the CAA. By allowing the regulation of GHGs under the CAA, the EPA’s findings also indirectly impacted many other carbon-intensive industries, which would potentially become subject to federal New Source Review Prevention of Significant Deterioration and Title V permitting requirements under the CAA (the “CAA Permitting Requirements”). Although we are not currently subject to reporting requirements under GHGs-related regulations, the future adoption of any regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the Nixon refinery could require us to incur significant costs and expenses or changes in operations, which could adversely affect our operations and financial condition.

 

Renewable Fuels

 

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA issued Renewable Fuels Standards (“RFS”) that require the blending of biofuels into transportation fuel. Since the compliance mechanism for RFS - Renewable Identification Numbers – would have created a burden on the Nixon refinery related to its nonroad, locomotive, and marine production through 2014, LE applied for an extension of the temporary exemption afforded small refineries through December 31, 2010 under the CAA Section 211(o)(9)(B). The EPA granted the Nixon refinery a small refinery exemption from RFS requirements for 2013 and 2014. Since 2014, the Nixon refinery has solely produced HOBM, a non-transportation lubricant blend product that does not fall under RFS.

 

Hazardous Substances and Wastes

 

The Comprehensive Environmental Response, Compensation, and Liability Act (“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. As of the filing of this Annual Report, neither we nor any of our predecessors have been designated as a potentially responsible party under CERCLA or a similar state statute.

 

 

 

The Resource Conservation and Recovery Act (“RCRA”) and comparable state and local laws impose requirements related to the handling, storage, treatment and disposal of solid and hazardous wastes. Our refining operations generate petroleum product wastes, solid wastes, and ordinary industrial wastes, such as from paints and solvents, that are regulated under RCRA and state law. Certain other wastes generated by the Nixon refinery are currently exempt from regulation as hazardous wastes but are subject to non-hazardous waste regulations. In the future, these wastes could be designated as hazardous wastes under RCRA or other applicable statutes and therefore may become subject to more rigorous and costly requirements.

 

The Nixon refinery has been used for refining activities for many years. Although prior owners and operators may have used operating and waste disposal practices that were standard in the industry at the time, petroleum hydrocarbons and various wastes may have been released on or under the Nixon Facility site. Regulatory audits to date have revealed no hazardous substance and waste issues.

 

Water Discharges

 

The Clean Water Act (the “CWA”) and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into federal and state waters. These laws affect our crude oil and condensate processing operations, our petroleum storage and terminaling operations, and our pipeline, facilities, and exploration and production assets. 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. Stormwater at the Nixon Facility is tested and discharged pursuant to applicable stormwater 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.

 

Spill Prevention and Control

 

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. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA or analogous state laws and regulations. The EPA regulates inland oil spills. See “Offshore Safety and Environmental Oversight” within this governmental regulation section for information on oil spills that occur in coastal waters.

 

Offshore Safety and Environmental Oversight

 

In addition to the CAA, our pipeline, exploration and production assets are also subject to the requirements of the Outer Continental Shelf Lands Act (the “OCSLA”). The OCSLA is administered by the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Office of Natural Resources Revenue. BSEE has partnered with the U.S. Coast Guard for oil spill response.

 

Spill Liability. The Oil Pollution Act of 1990 (“OPA”), which amends oil spill provisions of the Clean Water Act (“CWA”), imposes duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. With limited exceptions, responsible parties are liable for all removal costs and damages arising from oil spills. Damages may include: injury or economic losses resulting from destruction of real or personal property, damages or loss of use of natural resources used for subsistence, lost tax revenue, royalties, rents, or net profit shares suffered by federal, state, or local governments due to injury to real or personal property, lost profits or impaired earning power because of injury to real or personal property or natural resources, and the net costs of providing increased or additional public services during or after removal activities.

 

BOEM increased the offshore limit of liability for damages under the OPA from $133.7 million to $137.7 million, plus all clean-up costs, to reflect the increase in the Consumer Price Index since 2013. The onshore facilities limit of liability for damages under the OPA is $633.9 million. A party cannot take advantage of the liability limits if the spill is caused by gross negligence or willful misconduct or resulted from a violation of federal safety, construction or operating regulations. If a party fails to report a spill or cooperate in the clean-up, liability limits do not apply. The OPA requires responsible parties to provide proof of financial responsibility for potential spills. The amount required for certain types of offshore

 

 

facilities located seaward of the seaward boundary of a state, including properties used for oil transportation, is $35.0 million. BDPL maintains the statutory $35.0 million coverage.

 

Spill Response. Pursuant to the OPA, the National Oil and Hazardous Substances Pollution Contingency Plan, more commonly called the National Contingency Plan, provides a blueprint for responding to both oil spills and hazardous substance releases. The National Contingency Plan requires, among other things, that responsible parties have an oil spill response plan in place. We have an oil spill response plan in place.

 

Idle Iron. BSEE requires operators to decommission wells and platforms that have not been used in the past five (5) years for exploration and development operations or as infrastructure to support such operations.

 

BDPL’s Blue Dolphin Pipeline has been inactive since September 2012. Due to the length of inactivity, BSEE required BDPL to: (i) flush and fill the Blue Dolphin Pipeline, (ii) abandon-in-place a portion of the Blue Dolphin Pipeline’s 20” segment and certain smaller diameter connecting lateral lines that reside offshore in federal waters and (iii) remove from federal waters the GA-288C anchor platform. In April 2016, BDPL submitted decommissioning permit applications to BSEE for three (3) pipeline segments – Segments #13101, #9428, and #15635 – and the GA-288C anchor platform. In June 2016, BDPL also submitted a decommissioning permit application to the U.S. Army Corps of Engineers for abandonment of Segment #9428. The permit applications were granted by BSEE at varying dates between August 2016 and April 2017. Work must typically be completed within 120 days from the date of permit approval. Abandonment timing primarily depends on resource availability and weather conditions in the Gulf of Mexico. Management anticipates performing abandonment work during 2019. Weather conditions in the Gulf of Mexico during the winter months is typically not conducive to abandonment operations. As of the date of this Annual Report, decommissioning work has not yet been completed.

 

In a letter dated December 19, 2018, BSEE issued to BDPL an Incident of Noncompliance (“INC”) for its failure to flush and fill Segment #13101 pursuant to the pipeline decommissioning approval letter issued in March 2017. BSEE asserts that the INC authorizes BSEE to impose financial penalties on BDPL if it does not comply with the INC within ten (10) days. As of the date of this Annual Report, flushing of the pipeline segment has not yet commenced.

 

BDPL has advised BOEM that flushing and abandonment work has not yet been completed. There can be no assurance that BSEE will not impose penalties under the INC. As a result, we are unable to predict BOEM’s response or the ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded a liability on our consolidated balance sheet as of December 31, 2018. As of December 31, 2018 and 2017, BDPL maintained $2.6 million and $2.3 million, respectively, in asset retirement obligations related to abandonment of these assets. If BDPL is assessed significant penalties under the INC, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition.

 

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

 

In a letter dated March 30, 2018, BOEM ordered BDPL to provide additional supplemental bonds or acceptable financial assurance of approximately $4.8 million (the “Separate Orders”) within sixty (60) calendar days of receipt of the letter. The Separate Orders relate to five (5) existing pipeline rights-of-way. BOEM issued an INC for each Separate Order dated June 8, 2018 and received by BDPL on June 11, 2018. BOEM asserts that the INCs authorize BOEM to impose financial penalties on BDPL if it does not comply with the Separate Orders within twenty (20) days. BOEM asserts that potential penalties accrue for each day BDPL failed to comply after June 28, 2018.  BDPL appealed the INCs on August 8, 2018. The Interior Board of Land Appeals (the “IBLA”) has granted four extension requests that extend BDPL’s deadline for filing a Statement of Reasons with the IBLA until April 22, 2019. BDPL’s pending appeal of the INCs does not relieve BDPL of its obligations to provide additional financial assurance in accordance with the Separate Orders, or of BOEM’s authority to impose financial penalties.

 

 

BDPL has initiated settlement discussions with BOEM to resolve the Separate Orders and the INCs. There can be no assurance that BOEM will: (i) accept a proposal for a reduced amount of supplemental financial assurance, (ii) not require additional supplemental pipeline bonds related to BDPL’s existing pipeline rights-of-way, and/or (iii) not impose penalties under the INCs. As a result, we are unable to predict the outcome of the Separate Orders, the settlement discussions with BOEM or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded a liability on our consolidated balance sheet as of December 31, 2018. As of December 31, 2018 and 2017, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM. If BDPL is required by BOEM to provide significant additional supplemental bonds or acceptable financial assurance or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition.

 

Offshore Safety. Under the Workplace Safety Rule, BSEE requires operators to employ a comprehensive safety and environmental management system (“SEMS”).  SEMS are designed to reduce human and organizational errors as root causes of work-related accidents and offshore spills, develop protocols as to who at the facility has the ultimate operational safety and decision-making authority, and establish procedures to provide all personnel with “stop work” authority. BSEE regulations require that an operator’s SEMS program must be periodically audited by an independent third-party auditor. BDPL has a SEMS program in place.

 

Health, Safety and Maintenance

 

We are subject to federal and state laws and regulations related to the health and safety of workers pursuant to the Occupational Safety and Health Act of 1970. These laws and regulations are administered by the Occupational Safety and Health Administration (the “OSHA”) and by states that have established an OSHA-approved state safety plan.

 

Our refinery operations are also subject to OSHA process safety management regulations and the National Emphasis Program for Petroleum Refineries (the “RNEP”). RNEP requires refineries to be inspected for compliance with process safety management regulations. Inspections may last from two to six months, including one to three months on site. Inspectors primarily focus on process safety management implementation and recordkeeping. The Nixon Facility was inspected by OSHA in 2013 and again in 2016. Following each inspection, LE was assessed a nominal civil penalty related to failure to comply with documentation and notice posting requirements.

 

We operate a comprehensive safety, health and security program, with participation by personnel at all levels of the organization. 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 routinely monitor our programs and consider improvements in our management systems.

 

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.

 

Personnel

 

We rely on the services of LEH pursuant to the Amended and Restated Operating Agreement to manage our property and the property of our subsidiaries in the ordinary course of business. LEH provides us with the following personnel services under the Amended and Restated Operating Agreement:

 

 

 

 

All personnel work for and are paid by LEH. Blue Dolphin is billed by LEH at cost plus a 5% markup. As of December 31, 2018, Blue Dolphin had 55 full-time workers. See “Part II, Item 8. Financial Statements and Supplementary Data - Note (9), Related-Party Transactions” of this Annual Report for additional disclosures related to LEH.

 

Available Information

 

We are subject to the informational requirements of the Exchange Act. We file financial and other information with the SEC as required, including but not limited to, proxy statements on Schedule 14A, Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549, on official business days during the hours of 10:00 a.m. to 3:00 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website at http:///www.sec.gov that contains reports, proxy information and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

 

We also make our SEC filings available through our website (http://www.blue-dolphin-energy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

ITEM 1A.  RISK FACTORS

 

An investment in our Common Stock involves risks. In addition to the other information in this Annual Report and our other filings with the SEC, you should carefully consider the following risk factors in evaluating us and our business. The risks described below are not the only risks we face. Additional risks and uncertainties not specified herein, not currently known to us, or currently deemed to be immaterial may also materially adversely affect our business, financial condition, operating results and/or cash flows.

 

Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required to do so.

 

 

 

As previously disclosed, LE was involved in arbitration proceedings with GEL, an affiliate of Genesis, related to a contractual dispute involving the Crude Supply Agreement and the Joint Marketing Agreement. On August 11, 2017, the arbitrator delivered the Final Arbitration Award. The Final Arbitration Award denied all LE’s claims against GEL and granted substantially all the relief requested by GEL in its counterclaims. Among other matters, the Final Arbitration Award awarded damages and GEL’s attorneys’ fees and related expenses to GEL in the aggregate amount of $31.3 million. After the initial $3.7 million payment to GEL in September 2017, LE has made payments to GEL of $0.5 million per month. As of the date of this Annual Report, LE has paid $11.7 million to GEL towards reducing the outstanding balance of the Final Arbitration Award.

 

A hearing on confirmation of the Final Arbitration Award was scheduled to occur on September 18, 2017 in state district court in Harris County, Texas. Prior to the scheduled hearing, LE and GEL jointly notified the court that the hearing would be continued for a period of no more than 90 days after September 18, 2017 (the “Continuance Period”), to facilitate settlement discussions between the parties. On September 26, 2017, LE and Blue Dolphin, together with LEH and Jonathan Carroll, entered into a Letter Agreement with GEL, effective September 18, 2017 (the “GEL Letter Agreement”), confirming the parties’ agreement to the continuation of the confirmation hearing during the Continuance Period, subject to the terms of the GEL Letter Agreement. The GEL Letter Agreement was subsequently amended nine times to extend the Continuance Period through July 2018.

 

 

The Lazarus Parties entered into the Settlement Agreement, whereby GEL and the Lazarus Parties agreed to the Settlement, subject to the terms and conditions set forth in the Settlement Agreement. The Settlement is conditioned upon the Settlement Payment and the Interim Payments or the Settlement Agreement is terminated. The Interim Payments will not be applied to reduce the amount of the Settlement Payment, but such payments will reduce the Final Arbitration Award. At the time of the Settlement, the difference between the Settlement Payment and the amount we have accrued on our consolidated balance sheet for arbitration award payable will be recognized as a gain on our consolidated statement of operations. At December 31, 2018 and 2017, accrued arbitration award payable on our consolidated balance sheet was $21.1 million and $27.1 million, respectively.

 

Unless extended in writing by GEL, the Settlement Agreement will terminate on July 31, 2019 if the Settlement Payment is not made on or before such date, and the Settlement Agreement may be terminated by GEL following the occurrence of an event of default under the Settlement Agreement, as described above. Pursuant to the Settlement Agreement, the parties agreed to terminate the GEL Letter Agreement, and GEL agreed not to take any action to execute or collect on the Final Arbitration Award and to take all action necessary to continue the District Court Action until the earlier of: (i) the date on which the Settlement Payment is paid or (ii) the termination of the Settlement Agreement. On February 1, 2019, GEL filed a proposed order granting a joint motion to continue the District Court Action.

 

Veritex, as successor in interest to Sovereign Bank by merger, delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements. The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available.

 

Veritex has not accelerated or called due the secured loan agreements considering the Settlement Agreement, which Veritex must ultimately approve. Instead, Veritex has expressly reserved all of its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2018 and 2017 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future.

 

Veritex has been working with LE and LRM and continues to be aware and party to all discussions and arrangements with GEL surrounding the Settlement. We can provide no assurance that the conditions necessary for consummation of the Settlement will be met. If certain conditions are not met or the Settlement Agreement is terminated, GEL may seek to enforce the Final Arbitration Award against the Lazarus Parties. Further, we can provide no assurance as to whether Veritex, as first lienholder, will approve the Settlement. If Veritex does not approve the Settlement, Veritex may exercise its rights and remedies under the secured loan agreements. In either case: (i) our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations will be materially affected, (ii) Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws, and (iii) the trading prices 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.

 

See “Part I, Item 3. Legal Proceedings,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the notes to our consolidated financial statements in “Part II, Item 8. Financial Statements and Supplementary Data” for additional information regarding the Final Arbitration Award, the Settlement Agreement with GEL, and our long-term debt.

 

 

 

We currently rely on revenue from operations, LEH and its affiliates (including Jonathan Carroll), and borrowings under bank facilities to meet our liquidity needs. Our short-term working capital needs are primarily related to acquisition of crude oil and condensate to operate the Nixon refinery, repayment of debt obligations, and capital expenditures for maintenance, upgrades, and refurbishment of equipment at the Nixon Facility. Our long-term working capital needs are primarily related to repayment of long-term debt obligations. In addition, we continue to utilize capital to reduce operational, safety and environmental risks. We may incur substantial compliance costs relating to any new environmental, health and safety regulations. Our liquidity will affect our ability to satisfy any of these needs.

 

We reported a net loss of $0.5 million, or a loss of $0.05 per share for the twelve months ended December 31, 2018 compared to a net loss of $22.3 million, or a loss of $2.09 per share, for the twelve months ended December 31, 2017. The twelve months ended December 31, 2017 included the net effect to our consolidated statement of operations of the Final Arbitration Award, which was an expense of $24.3 million, or $2.29 per share, in arbitration award and associated fees.  Excluding the Final Arbitration Award, we would have reported net income for the twelve months ended December 31, 2017 of $2.0 million, or income of $0.19 per share, reflecting a decline of $2.5 million, or $0.24 per share, for 2018 compared to 2017 due to lower margins.

 

We had a working capital deficit of $71.9 million at December 31, 2018 compared to a working capital deficit of $69.5 million at December 31, 2017. Excluding the current portion of long-term debt, we had a working capital deficit of $30.0 million at December 31, 2018 and 2017.

 

We had cash and cash equivalents and restricted cash (current portion) of $0.01 million and $0.05 million, respectively, at December 31, 2018. Comparatively, we had cash and cash equivalents and restricted cash (current portion) of $0.5 million and $0.05 million, respectively, at December 31, 2017.

 

[See “Part I, Item 1. Business – Going Concern,” “ – Operating Risks,” and “ – Business Strategy” for additional disclosures related to certain factors (including net losses, working capital deficits, and defaults under secured loan agreements) that could have a material adverse effect on our liquidity and the steps management is continuing to take to improve operations at the Nixon Facility.]

 

 

As described elsewhere in this Annual Report, Veritex notified obligors that the Final Arbitration Award constitutes an event of default under secured loan agreements with Veritex. In addition to existing events of default related to the Final Arbitration Award, at December 31, 2018, LE and LRM were in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the secured loan agreements. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the secured loan agreements permits Veritex to declare the amounts owed under the secured loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under the loan agreements, and/or exercise any other rights and remedies available. Veritex has not accelerated or called due the secured loan agreements considering the Settlement Agreement, which Veritex must ultimately approve. Instead, Veritex has expressly reserved all its rights, privileges and remedies related to events of default under the secured loan agreements and informed LE and LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2018 and 2017 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future.

 

 

We can provide no assurance that: (i) our assets or cash flow would be sufficient to fully repay borrowings under outstanding long-term debt, either upon maturity or if accelerated, (ii) LE and LRM would be able to refinance or restructure the payments on the long-term debt, and/or (iii) Veritex, as first lien holder, will approve the Settlement or provide future waivers. Veritex has been working with LE and LRM and continues to be aware and party to all discussions and arrangements with GEL surrounding the Settlement. If Veritex does not approve the Settlement, Veritex may exercise its rights and remedies under the secured loan agreements. Defaults under secured loan agreements and any exercise by Veritex of its rights and remedies related to such defaults may have a material adverse effect on the trading prices of our common stock and on the value of an investment in our common stock, and holders of our common stock could lose their investment in our common stock in its entirety, particularly if Blue Dolphin is required to seek protection under bankruptcy laws.

 

For additional information regarding defaults under our secured loan agreements and their potential effects on our business, financial condition, and results of operations, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (11) Long-Term Debt, Net”.

 

 

As of December 31, 2018 and 2017, we had $34.9 million and $35.5 million, respectively, of bank debt in the current portion of long-term debt. Blue Dolphin, as parent company, has guaranteed the indebtedness of certain subsidiaries. In addition, LEH and certain LEH affiliates have guaranteed the indebtedness of Blue Dolphin and certain of its subsidiaries. This level of debt in current liabilities and the cross guarantee agreements could have important consequences, such as: (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth, or for other purposes; (ii) increasing the cost of future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

 

As of the date of this Annual Report, LE and LRM are current with payments under their respective secured loan agreements with Veritex. Our ability to service debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our working capital is not sufficient to service our debt, and any future indebtedness that we incur, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin would likely be required to seek protection under bankruptcy laws.

 

 

Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings (which would have a corresponding impact on the credit ratings of our subsidiaries that are party to any cross-guarantee agreements) could cause our cost of doing business to increase by limiting our access to capital, including our ability to refinance maturing or accelerated existing indebtedness on similar terms.

 

 

Jonathan Carroll, our Chief Executive Officer, President, Assistant Treasurer and Secretary, is also a majority owner of LEH. Together, LEH and Jonathan Carroll owned 79.8% of our Common Stock at December 31, 2018, and, pursuant to the Amended and Restated Operating Agreement, manages and operates all Blue Dolphin properties. LEH and Jonathan Carroll have significant influence over matters such as the election of the Board, control over our business, policies and affairs and other matters submitted to our stockholders. LEH and Jonathan Carroll are entitled to vote the Common Stock owned by LEH in accordance with its interests, which may be contrary to the interests of other stockholders. LEH has interests that may differ from the interests of other stockholders and, as a result, there is a risk that important business decisions will not be made in the best interest of some of our stockholders.

 

 

LEH and its affiliates are not limited in their ability to compete with us and are not obligated to offer us business opportunities. We believe that the transactions and agreements that we have entered with LEH and its affiliates are on terms that are at least as favorable as could reasonably have been obtained at such time from third parties. However, 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 LEH or its affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public’s perception of us, as well as our relationship with other companies and our ability to enter new relationships in the future, which may have a material adverse effect on our ability to do business.

 

 

Oil and gas operations are inherently subject to significant hazards and risks. These hazards and risks include, but are not limited to, fires, explosions, ruptures, blowouts, spills, third-party interference and equipment failure, any of which could result in interruption or termination of operations, pollution, personal injury and death, or damage to our assets and the property of others. These risks could harm our reputation and business, result in claims against us, and have a material adverse effect on our results of operations and financial condition.

 

 

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

 

 

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

 

 

Our 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.

 

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.

 

 

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

 

 

Our insurance coverage does not cover all potential losses, costs or liabilities. We could suffer losses for uninsurable or uninsured risks or in amounts more than our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. In addition, if we experience insurable events, we may experience an increase in annual premiums, a limit on coverage, or loss of coverage. Inadequate insurance or loss of coverage could have a material adverse effect on our business, financial condition, and results of operations.

 

 

Under Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years).

 

Blue Dolphin experienced ownership changes in 2005 because of a series of private placements, and in 2012 because of a reverse acquisition. The 2012 ownership change limits our ability to utilize NOLs following the 2005 ownership change that were not previously subject to limitation. Limitations imposed on our ability to use NOLs to offset future taxable income could cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect, and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes. NOLs generated after the 2012 ownership change are not subject to limitation.

 

 

At December 31, 2018 and 2017, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of December 31, 2018 and 2017.

 

 

Energy-related assets in the U.S. may be at a greater risk for future terrorist attacks than other potential targets. A direct attack on our assets or assets used by us could have a material adverse effect on our operations, financial condition, results of operations, and cash flows. In addition, any terrorist attack in the U.S. could have an adverse impact on energy prices, including prices for crude oil and refined petroleum products, and refining margins. Disruption or significant increases in energy prices could result in government-imposed price controls. While we currently maintain some insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms that we consider affordable, or at all.

 

Our operations are dependent on our technology infrastructure, which includes a data network, telecommunications system, internet access, and various computer hardware equipment and software applications. Our technology infrastructure is subject to damage or interruption from several potential sources, including natural disasters, software viruses or other malware, power failures, cyber-attacks, and/or other events. To the extent that our technology infrastructure is under our control, we have implemented measures such as virus protection software and emergency recovery processes to address identified risks. However, there can be no assurance that a security breach or cyber-attack will not compromise confidential, business critical information, cause a disruption in our operations, or harm our reputation, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

 

 

Management has determined that conditions exist that raise substantial doubt about our ability to continue as a going concern due to the Final Arbitration Award, defaults in secured loan agreements, recurring losses from operations, and the substantial decline in working capital. A “going concern” opinion could impair our ability to finance our operations through the sale of equity, incurring debt, or other financing alternatives. Our ability to continue as a going concern will depend upon consummation of the Settlement with GEL, sustained positive operating margins, and financing at commercially reasonable terms for working capital to operate the Nixon Facility, purchase crude oil and condensate, and funding for capital expenditures.  If we are unable to achieve these goals, our business would be jeopardized, and we may not be able to continue.

 

 

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our refined petroleum product sales prices and our crude oil and condensate costs. Our crude oil and condensate acquisition costs and the prices at which we can ultimately sell our refined petroleum products depend upon numerous factors beyond our control. The prices at which we sell refined petroleum products are strongly influenced by the commodity price of crude oil. If crude oil prices increase, our “refinery operations” business segment margins will fall unless we can pass along these price increases to our wholesale customers. Increases in the selling prices for refined petroleum products typically trail the rising cost of crude oil and may be difficult to implement when crude oil costs increase dramatically over a short period.

 

 

 

Our refining earnings, cash flows and liquidity from operations depend primarily on the margin above operating expenses (including the cost of refinery feedstocks, such as crude oil and condensate that are processed and blended into refined petroleum products) at which we can sell refined petroleum products. Crude oil refining is primarily a margin-based business. To improve margins, it is important for a crude oil refinery to maximize the yields of high value finished petroleum produces and to minimize the costs of feedstocks and operating expenses. When the margin between refined petroleum product prices and crude oil and other feedstock costs decreases, our margins are negatively affected. Crude oil refining margins have historically been volatile, and are likely to continue to be volatile, because of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined petroleum products, and fuel and utility services. Although an increase or decrease in the price for crude oil generally results in a similar increase or decrease in prices for refined petroleum products, typically there is a time lag between the comparable increase or decrease in prices for refined petroleum products. The effect of changes in crude oil and condensate prices on our refining margins therefore depends, in part, on how quickly and how fully refined petroleum product prices adjust to reflect these changes.

 

Prices of crude oil, other feedstocks and refined petroleum products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, and refined petroleum products. Such supply and demand are affected by, among other things:

 

●	changes in foreign, domestic, and local economic conditions;

 

●	foreign and domestic demand for fuel products;

 

●	worldwide political conditions, particularly in significant oil producing regions;

 

●	foreign and domestic production levels of crude oil, other feedstocks, and refined petroleum products and the volume of crude oil, feedstocks, and refined petroleum products imported into the U.S.;

 

●	availability of and access to transportation infrastructure;

 

●	capacity utilization rates of refineries in the U.S.;
●	Organization of Petroleum Exporting Countries’ influence on oil prices;

 

●	development and marketing of alternative and competing fuels;

 

●	commodities speculation;

 

●	natural disasters (such as hurricanes and tornadoes), accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries;

 

●	federal and state governmental regulations and taxes; and

 

●	local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.

 

 

 

Operation of the Nixon refinery depends on our ability to purchase adequate crude supplies on favorable terms. Following the cessation of crude supplies under the Crude Supply Agreement with GEL, we put in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect the supplier to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, as well as other factors, including as net losses, working capital deficits, and financial covenant defaults in secured loan agreements.

 

We are pursuing alternative sources to finance crude oil and condensate acquisition costs, including commodity sale and repurchase programs, inventory financing, debt financing, equity financing, or other means. We may not be successful in consummating suitable financing transactions in the time required or at all, securing financing on terms favorable to us, or obtaining crude oil and condensate at the levels needed to earn a profit and/or safely operate the Nixon Facility, any of which could adversely affect our business, results of operations and financial condition.

 

 

The safe and reliable operation of the Nixon refinery is key to our financial performance and results of operations, and we are particularly vulnerable to disruptions in our operations because all our refining operations are conducted at a single facility. Although operating at anticipated levels, the Nixon refinery is still in a recommissioning phase and may require unscheduled downtime for unanticipated reasons, including maintenance and repairs, voluntary regulatory compliance measures, or cessation or suspension by regulatory authorities. Occasionally, the Nixon refinery experiences a temporary shutdown due to power outages because of high winds and thunderstorms. In the case of such a shutdown, the refinery must initiate a standard start-up process, and such process can last several days although we are typically able to resume normal operations the next day. Any scheduled or unscheduled downtime may result in lost margin opportunity, increased maintenance expense and a build-up of refined petroleum products inventory, which could reduce our ability to meet our payment obligations.

 

For the twelve months ended December 31,2018, the refinery experienced thirty (30) days of downtime primarily related to repair and maintenance of the naphtha stabilizer unit and short maintenance turnarounds scheduled during January and March of 2018. For the twelve months ended December 31, 2017, the refinery experienced seventeen (17) days of downtime primarily due to a contract-related dispute with GEL and Hurricane Harvey. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional disclosures related to the performance of the Nixon refinery.

 

 

If we are unable to generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. We currently rely on revenue from operations, including sales of refined petroleum products and rental of petroleum storage tanks, LEH and its affiliates (including Jonathan Carroll), and borrowings under bank facilities to meet our liquidity needs. At December 31, 2018 and 2017, accounts payable, related party was $1.5 million and $1.0 million, respectively.

 

 

In the event our working capital requirements are inadequate, or we are otherwise unable to secure sufficient liquidity to support our short term and/or long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, any of which may have a material adverse effect on our results of operations or liquidity. Our short-term working capital needs are primarily related to acquisition of crude oil and condensate to operate the Nixon refinery, repayment of debt obligations, and capital expenditures for maintenance, upgrades, and refurbishment of equipment at the Nixon Facility. Our long-term working capital needs are primarily related to repayment of long-term debt obligations. Our liquidity will affect our ability to satisfy all these needs.

 

 

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. 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.

 

 

For the twelve months ended December 31, 2018, we had 4 customers that accounted for approximately 91% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 29% of our refined petroleum product sales.  At December 31, 2018, these 4 customers represented approximately $0.1 million in accounts receivable.  LEH represented approximately $0 million in accounts receivable. LEH purchases our jet fuel and resells the jet fuel to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. (See “Part I, Item 1. Business – Structure and Management” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (9) Related-Party Transactions, Note (11) Long-Term Debt, Net, and Note (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.)

 

For the twelve months ended December 31, 2017, we had 3 customers that accounted for approximately 70% of our refined petroleum product sales. LEH was 1 of these 3 significant customers and accounted for approximately 33% of our refined petroleum product sales.  At December 31, 2017, these 3 customers represented approximately $1.3 million in accounts receivable.  LEH represented approximately $0.7 in accounts receivable.

 

Our customers have a variety of suppliers to choose from and therefore can make substantial demands on us, including demands on product pricing and on contractual terms, which often results in the allocation of risk to us as the supplier. 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 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 prices and other terms of sale. We could decide not to sell our refined petroleum 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.

 

 

 

Our success in the wholesale market depends in large part on our ability to maintain and grow our image and reputation as a reliable operator and to expand into and gain market acceptance of our refined petroleum products. Adverse perceptions of product quality, whether justified, or allegations of product quality issues, even if false or unfounded, could tarnish our reputation and cause our wholesale customers to choose refined petroleum products offered by our competitors.

 

 

We rely on trucks for the receipt of crude oil and condensate into and the sale of refined petroleum 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 petroleum 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, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in that area.

 

 

Our primary operating assets are in Nixon, Texas in the Eagle Ford Shale, and we market our refined petroleum products in a single, relatively 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 petroleum products to customers outside of our current operating region and thus incur considerably higher transportation costs, resulting in lower refining margins.

 

 

 

Continued political focus on climate change, human activities contributing to the release of large amounts of carbon dioxide and other GHGs into the atmosphere, and potential mitigation through regulation could have a material impact on our operations and financial results. International agreements and federal, state and local regulatory measures to limit GHG emissions have been in various stages of discussion and implementation. These and other GHG emissions-related laws, policies, and regulations may result in substantial capital, compliance, operating, and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted in each jurisdiction, our activities in the particular jurisdiction, and market conditions. The effect of regulation on our financial performance will depend on many factors including, among others, the sectors covered, the GHG emissions reductions required by law, the extent to which we would be entitled to receive emission allowance allocations, our ability to acquire compliance related equipment, the price and availability of emission allowances and credits, and our ability to recover incurred regulatory compliance costs through the pricing of our products. Material price increases or incentives to conserve or use alternative energy sources could also reduce demand for products we currently sell and adversely affect our sales throughput volumes, revenues and margins.

 

 

 

To cover the various obligations of lessees on the Outer Continental Shelf, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, BOEM generally requires that lessees demonstrate financial strength and reliability per regulations or post bonds or other acceptable assurances that such obligations will be satisfied.

 

BOEM ordered BDPL to provide additional supplemental pipeline bonds or acceptable financial assurance of approximately $4.8 million related to five (5) existing pipeline rights-of-way. At December 31, 2018 and 2017, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to BOEM. Of the five (5) existing pipeline rights-of-ways related to BOEM’s request, the pipeline associated with one (1) right-of-way was decommissioned in 1997. Management is seeking a reduction in the amount of BOEM’s request for additional financial assurance. There can be no assurance that BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way. If BDPL is required by BOEM to provide significant additional supplemental bonds or acceptable financial assurance or if BOEM imposes penalties under INCs for failure to meet orders to increase bonds or other sureties, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

 

 

BSEE requires operators to decommission wells and platforms that have not been used in the past five (5) years for exploration or development operations or as infrastructure to support such operations. BDPL holds non-operating leasehold interests in several wells, all of which have been plugged and abandoned by their operators. BDPL owns several pipelines in the Gulf of Mexico that are currently inactive. Although management has used its best efforts to determine future AROs, assumptions and estimates can be influenced by many factors beyond management’s control. Such factors include, but are not limited to, changes in regulatory requirements, changes in costs for abandonment related services and technologies, which could increase or decrease based on supply and demand, and/or extreme weather conditions, such as hurricanes, which may cause structural or other damage to pipeline and related assets and oil and gas properties. At December 31, 2018 and 2017, our estimated future asset retirement obligations were approximately $2.6 million and $2.3 million, respectively. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (12) Asset Retirement Obligations” of this Annual Report for additional information regarding asset retirement obligations.

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS

 

None.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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ITEM 2.  PROPERTIES

 

LEH manages and operates all Blue Dolphin properties pursuant to the Amended and Restated Operating Agreement. Management believes that our properties are generally adequate for our operations and are maintained in a good state of repair in the ordinary course of business. Following is a summary of our principal facilities and assets:

 

Property		Operating Subsidiary			Location
Refinery Operations Tolling and Terminaling
● Nixon Facility (56 acres)		LE, LRM, NPS			Nixon, Texas
Corporate and Other
● Freeport Facility (162 acres)		BDPL			Freeport, Texas
● Pipelines and oil and gas working interests in wells		BDPL, BDPC			Gulf of Mexico
● Corporate headquarters		BDSC			Houston, Texas

 

Nixon Facility. See “Part I, Item 1. Business – Company Overview” and “– Nixon Facility” for a description of the Nixon Facility. The Nixon Facility’s business assets are pledged as collateral under certain of our long-term debt as discussed in “Part II, Item 8. Financial Statements and Supplementary Data – Note (11) Long-Term Debt, Net”.

 

Freeport Facility. The Freeport Facility includes pipeline easements and rights-of-way, crude oil and natural gas separation and dehydration facilities, a vapor recovery unit and two onshore pipelines. The two onshore pipelines consist of approximately 4 miles of the 20-inch Blue Dolphin Pipeline and a 16-inch natural gas pipeline that connects the Freeport Facility to the Dow Chemical Plant Complex in Freeport, Texas. In February 2017, BDPL sold approximately 15 acres of property located in Brazoria County, Texas to FLIQ Common Facilities, LLC, an affiliate of FLNG.

 

Pipelines and Oil and Gas Assets. We fully impaired our pipeline assets at December 31, 2016 and our oil and gas properties at December 31, 2011. Our pipeline and oil and gas properties had no revenue during the years ended December 31, 2018 and 2017. Although the pipelines are no longer active, management believes the pipelines have future operational potential and continues to explore business development opportunities.

 

The following provides a summary of our oil and gas and pipeline assets, all of which are in the Gulf of Mexico:

 

 

 

 

 

 

			Natural Gas
			Capacity
Pipeline	Ownership	Miles	(MMcf/d)
Blue Dolphin Pipeline(1)	100%	38	180
GA 350 Pipeline(1)	100%	13	65
Omega Pipeline(2)	100%	18	110

 

 

Corporate Headquarters. We lease 7,675 square feet of office space in Houston, Texas. Our office lease is discussed more fully in “Part II, Item 8. Financial Statements and Supplementary Data – Note (16) Leases” of this Annual Report.

ITEM 3.  LEGAL PROCEEDINGS

 

Final Arbitration Award and Settlement Agreement

 

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Going Concern – Final Arbitration Award and Settlement Agreement” of this Annual Report for disclosures related to the Final Arbitration Award to GEL and the Settlement Agreement between the Lazarus Parties and GEL.

 

Other Legal Matters

 

We are involved in lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens, contract-related disputes, administrative proceedings, and financial assurance (bonding) requirements with regulatory bodies. Management is in discussion with all concerned parties and does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows. However, there can be no assurance that such discussions will result in a manageable outcome or that we will be able to meet financial assurance (bonding) requirements. If Veritex does not approve the Settlement or exercises its rights and remedies under the secured loan agreements or if the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws.

ITEM 4.  MINE SAFETY DISCLOSURES

 

Not applicable.

 

 

 

 

 

 

 

Remainder of Page Intentionally Left Blank

 

 

PART II

 

 

Market Information

 

Our Common Stock currently trades on the OTCQX U.S. tier of the OTC Markets under the ticker symbol “BDCO." The following table sets forth, for the periods indicated, the high and low bid prices for our Common Stock as reported by the OTC Markets. The quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions.

 

Quarter Ended	High Bid	Low Bid
2018
December 31	$1.13	$0.40
September 30	$1.11	$0.22
June 30	$0.59	$0.11
March 31	$1.63	$0.53
2017
December 31	$0.90	$0.06
September 30	$1.77	$0.02
June 30	$2.75	$1.25
March 31	$4.00	$3.00

 

Stockholders

 

At April 1, 2019, we had 270 record holders of our Common Stock. We have approximately 3,000 beneficial holders of our Common Stock.

 

Dividends

 

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 not declared any dividends on our Common Stock during the last two fiscal years.

 

ITEM 6.  SELECTED FINANCIAL DATA

 

Not applicable.

 

 

You should read the following discussion together with the financial statements and the notes thereto included elsewhere in this Annual Report. This discussion contains forward-looking statements that are based on management’s current expectations, estimates, and projections about our business and operations. The cautionary statements made in this Annual Report should be read as applying to all related forward-looking statements wherever they appear in this Annual Report. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements due to many factors, including those we discuss under “Part I, Item 1A. Risk Factors” and elsewhere in this Annual Report. You should read such risk factors and forward-looking statements in this Annual Report.

 

Company Overview

 

See “Part I, Item 1. Business” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Operating Risks” for detailed information related to our business and operations and factors that management has determined raise substantial doubt about our ability to continue as a going concern.

 

Major Influences on Results of Operations

 

Refinery Operations

 

As a margin-based business, our refinery operations are primarily affected by gross profit per bbl, product slate, and refinery downtime.

 

Price Differentials per Bbl

 

Gross profit per bbl, which reflects the dollar per bbl price difference between crude oil and condensate (input) and refined petroleum products (output), is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. Our per bbl cost to acquire crude oil and condensate and the dollar per bbl price for which our refined petroleum products are ultimately sold depend on the economics of supply and demand. Supply and demand are affected by numerous factors, most, if not all, of which are beyond our control, including:

 

 

Product Slate

 

Management periodically determines whether to change the refinery’s product mix, as well as maintain, increase, or decrease inventory levels based on various factors. These factors include the crude oil pricing market in the U.S. Gulf Coast region, the refined petroleum products market in the same region, the relationship between these two markets, fulfilling contract demands, and other factors that may impact our operations, financial condition, and cash flows.

 

 

Refinery Downtime

 

The safe and reliable operation of the refinery is key to our financial performance and results of operations, and we are particularly vulnerable to disruptions in our operations because all our refining operations are conducted at a single facility. Although operating at anticipated levels, the refinery is still in a recommissioning phase and may require unscheduled downtime for unanticipated reasons, including maintenance and repairs, voluntary regulatory compliance measures, or cessation or suspension by regulatory authorities.

 

Occasionally, the Nixon refinery experiences a temporary shutdown due to power outages from high winds and thunderstorms. In such cases, we must initiate a standard refinery start-up process, which can last several days. We are typically able to resume normal operations the next day. Any scheduled or unscheduled downtime will result in lost margin opportunity, potential increased maintenance expense and a reduction of refined petroleum products inventory, which could reduce our ability to meet our payment obligations.

 

Tolling and Terminaling Operations

 

The Nixon Facility’s petroleum storage tanks and infrastructure are primarily suited for crude oil and condensate and refined petroleum products, such as naphtha, jet fuel, diesel and fuel oil. Our storage terminaling operations are primarily affected by:

 

 

Key Relationships

 

Relationship with LEH

 

Blue Dolphin and certain of its subsidiaries are currently parties to a variety of agreements with LEH and its affiliates and a counter-party. Related-party agreements with LEH include: (i) an Amended and Restated Operating Agreement with Blue Dolphin and LE, (ii) a Jet Fuel Sales Agreement with LE, (iii) a Loan Agreement with BDPL, (iv) an Amended and Restated Promissory Note with Blue Dolphin, and (v) a Debt Assumption Agreement with LE, and (vi) an office sub-lease agreement with BDSC. In addition, we currently rely on advances from LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. There can be no assurances that LEH and its affiliates will continue to fund our working capital requirements. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (9) Related-Party Transactions” for additional disclosures related to agreements that we have in place with LEH and its affiliates.)

 

Relationship with Crude Supplier

 

Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect the supplier to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, as well as other factors, including as net losses, working capital deficits, and financial covenant defaults in secured loan agreements.

 

Management believes that it is taking the appropriate steps to improve our operations and financial stability. If our business strategy is unsuccessful, it could affect our ability to acquire adequate supplies of crude oil and condensate under the existing contract or otherwise. Further, because our existing crude supply contract is a month-to-month arrangement, there can be no assurance that crude oil and condensate supplies will continue to be available under this contract in the future.

 

 

Results of Operations

 

Certain prior year amounts have been reclassified in order to conform to the current year presentation. Additionally, certain changes to the presentation of prior period statements of operations have been made to conform to the current period presentation, primarily relating to: (i) a retitling from ‘cost of sales’ to ‘cost of goods sold,’ which includes all costs directly attributable to the generation of the related revenue, as defined by GAAP and (ii) a breakout of the ‘LEH operating fee’ under the Amended and Restated Operating Agreement, which was previously reported within ‘refinery operating expenses’. These changes had no effect on the reported results of operations.

 

Consolidated Results

Twelve Months Ended December 31, 2018 (the “Current Year”) Compared to December 31, 2017 (the “Prior Year”).

Total Revenue from Operations. For the Current Year, we had total revenue from operations of $340.8 million compared to total revenue from operations of $258.4 million for the Prior Year, an increase of approximately 32%. Approximately 99% of our revenue is derived from refinery operations while 1% is derived from tolling and terminaling. Refinery operations revenue increased approximately $81.5 million in the Current Year compared to the Prior Year. Of that increase, 90% was due to higher commodity pricing while 10% was due to slightly increased sales throughput volume. For the same period, tolling and terminaling revenue increased approximately $0.8 million, or 28%, as a result of increased storage fees under new and renewed customer agreements.

 

Total Cost of Goods Sold. Total cost of goods sold was $331.9 million for the Current Year compared to $248.4 million for the Prior Year. The 34% increase in total cost of goods sold in the Current Year compared to the Prior Year related to higher commodity prices for crude oil and chemicals and, to a lesser extent, increased direct operating expenses due to a Nixon refinery turnaround.

 

Gross Profit / Gross Margin. For the Current Year, gross profit totaled $8.8 million, or approximately 3%, compared to gross profit of $10.0 million, or approximately 4%, for the Prior Year. The decrease in gross profit between the periods primarily related to higher commodity prices for crude oil and chemicals and increased direct operating expenses, which was partially offset by increased tank rental revenue in the Current Year compared to the Prior Year.

 

LEH Operating Fee. The LEH operating fee under the Amended and Restated Operating Agreement totaled $0.6 million in the Current Year compared to $0.8 million in the Prior Year. The $0.2 million decrease in operating fee between the periods was the result of the fee restructure under the Amended and Restated Operating Agreement in April 2017. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (9) Related-Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement.)

 

Arbitration Award and Associated Fees.  The Final Arbitration Award awarded damages and GEL’s attorneys’ fees and related expenses to GEL in the aggregate amount of $31.3 million. However, the net effect to our consolidated statement of operations was an expense of $24.3 million in arbitration award and associated fees related to the Final Arbitration Award during the Prior Year. Arbitration award and associated fees totaled $0 for the Current Year.

 

General and Administrative Expenses. We incurred general and administrative expenses of $3.3 million in the Current Year compared to $4.0 million in the Prior Year. For the Current Year compared to the Prior Year, the 19% decrease in general and administrative expenses primarily related to lower legal fees.

 

Depletion, Depreciation and Amortization. We recorded depletion, depreciation and amortization expenses of $1.9 million in the Current Year compared to $1.8 million in the Prior Year, an increase of nearly 7%. The increase related to placement in service of a new boiler and new petroleum storage tanks.

 

Other Expense. Total other expense was $3.3 million in the Current Year compared to $0.5 million in the Prior Year. The Prior Year included a one-time gain on the sale of property.

 

Income Tax Benefit. We recognized an income tax benefit of $0.3 million in the Current Year compared to $0 in the Prior Year. Income tax benefit in the Current Year primarily related to a refundable Alternative Minimum Tax that was paid in prior periods. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (17) Income Taxes” for additional disclosures related to income taxes.)

 

 

Net Loss. For the Current Year, we reported a net loss of $0.5 million, or loss of $0.05 per share, compared to a net loss of $22.3 million, or loss of $2.09 per share, for the Prior Year. The Prior Year included the net effect to our consolidated statement of operations of the Final Arbitration Award, which was an expense of $24.3 million, or $2.29 per share, in arbitration award and associated fees.  Excluding the Final Arbitration Award, we would have reported net income in the Prior Year of $2.0 million, or income of $0.19 per share, reflecting a decline of $2.5 million, or $0.24 per share, for the Current Year compared to the Prior Year due to lower margins.

 

Non-GAAP Financial Measures

 

To supplement our consolidated results, management uses refining gross profit per bbl, a non-GAAP financial measure, to help investors evaluate our core operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. Refining gross profit per bbl is reconciled to GAAP-based results below. Refining gross profit per bbl should not be considered an alternative for GAAP results. Refining gross profit per bbl is provided to enhance an overall understanding of our core financial performance for the applicable periods and is an indicator that management believes is relevant and useful. Refining gross profit per bbl may differ from similar calculations used by other companies within the petroleum industry, thereby limiting its usefulness as a comparative measure. (See “Part II, Item 8. Financial Statements and Supplementary Data” for comparative GAAP results.)

Refining Gross Profit per Bbl – For the Current Year, refining gross profit per bbl was $1.14 compared to $1.63 per bbl for the Prior Year, reflecting a decrease of $0.49 per bbl. The decrease between the periods primarily related to less favorable margins for refined petroleum products in the Current Year compared to the Prior Year. (See “Glossary of Selected Energy and Financial Terms” in this Annual Report for the definition of gross margin per bbl.)

 

	Twelve Months Ended December 31,
	2018	2017
	(in thousands except per bbl amounts)
Refined petroleum product sales	$337,038	$255,547
Less: Total cost of goods sold	(331,936)	(248,433)
	5,102	7,114
Sales (Bbls)	4,493	4,359
Gross Margin per Bbl	$1.14	$1.63

 

 

 

 

 

 

 

 

 

 

Remainder of Page Intentionally Left Blank

 

 

Refinery Operations Throughput and Production Data

 

Operational metrics for the refinery for the periods indicated were as follow:

 

	Twelve Months Ended December 31,
	2018	2017
Calendar Days	365	365
Refinery downtime	(30)	(17)
Operating Days	335	348
Total refinery throughput (bbls)	4,605,705	4,488,658
Operating days:
bpd	13,748	12,898
Capacity utilization rate	91.7%	86.0%
Calendar days:
bpd	12,618	12,298
Capacity utilization rate	84.1%	82.0%
Total refinery production (bbls)	4,479,701	4,352,745
Operating days:
bpd	13,372	12,508
Capacity utilization rate	89.1%	83.4%
Calendar days:
bpd	12,273	11,925
Capacity utilization rate	81.8%	79.5%

 

Note:

The small difference between total refinery throughput (volume processed as input) and total refinery production (volume processed as output) represents a combination of multiple factors including refinery fuel use, elimination of some impurities originally present in the crude oil, loss, and other factors.

 

In the Current Year, the refinery experienced thirty (30) days of downtime primarily related to repair and maintenance of the naphtha stabilizer unit and short maintenance turnarounds scheduled in January and March of 2018. In the Prior Year, the refinery experienced seventeen (17) days of downtime primarily due to a contract-related dispute with GEL and Hurricane Harvey.

 

For the Current Year compared to the Prior Year, total refinery throughput bbls and total refinery production bbls increased nominally despite the refinery being down more days in the Current Year compared to the Prior Year. Typically, during the summer months refinery throughput volumes at the Nixon refinery are negatively impacted by the extreme Texas heat. For the Current Year, the Nixon refinery was positively impacted renting and utilizing a cooling unit. The cooling unit allowed the refinery to run more bbls per day, resulting in increased refinery throughput and production volumes in the periods despite refinery downtime. The cooling unit was not used during the Prior Year.

 

Refined Petroleum Product Sales Summary.

 

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (15) Concentration of Risk” for a discussion of refined petroleum product sales.

 

 

Liquidity and Capital Resources

 

Overview.

We currently rely on revenue from operations, LEH and its affiliates (including Jonathan Carroll), and borrowings under bank facilities to meet our liquidity needs. Primary uses of cash include: (i) payment to LEH for our direct operating expenses under the Amended and Restated Operating Agreement, (ii) payments on long-term debt and the Final Arbitration Award, (iii) purchase of crude oil and condensate, and (iv) construction in progress.

As discussed elsewhere within this “Liquidity and Capital Resources” section, management has determined that there is substantial doubt about our ability to continue as a going concern due to consecutive net losses, inadequate working capital, the Final Arbitration Award, and defaults under secured loan agreements. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Going Concern” for additional disclosures related to the Final Arbitration Award, the Settlement Agreement with GEL, defaults under secured loan agreements, and the going concern.

 

Management believes that it is taking the appropriate steps to improve our operations and financial stability. If our business strategy is unsuccessful, it could affect our ability to acquire adequate supplies of crude oil and condensate under our existing contract or otherwise. Further because our existing crude supply contract is an evergreen arrangement, there can be no assurance that crude oil and condensate supplies will continue to be available under our crude supply contract in the future.

 

Our results of operations and liquidity are highly dependent upon the margins that we receive for our refined petroleum products. The dollar per bbl price difference between crude oil and condensate (input) and refined petroleum products (output), is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. There can be no assurance that margins for refined petroleum products will be favorable, LEH and its affiliates will continue to fund our working capital needs in periods of working capital deficits, or we will be able to obtain additional financing on commercially reasonable terms or at all. Further, if Veritex Community Bank (“Veritex”) does not approve the Settlement or the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin would likely be required to seek protection under bankruptcy laws. (See “Part I, Item 1. Business – Business Strategy” for a discussion related to our business strategy.)

 

Crude Oil and Condensate Supply.

 

Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect the supplier to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, as well as other factors, including net losses, working capital deficits, and financial covenant defaults in secured loan agreements.

 

 

Cash Flow.

 

Our cash flow from operations for the periods indicated was as follows:

 

	Twelve Months Ended December 31,
	2018	2017
Beginning cash, cash equivalents, and restricted cash	$2,146	$6,083
Cash flow from operations
Reconciled net loss to net cash provided by operating activities	1,618	(19,659)
Change in assets and operating liabilities	(613)	14,715
Total cash flow from operations	1,005	(4,944)
Cash inflows (outflows)
Proceeds from issuance of debt	-	3,678
Payments on debt	(890)	(1,364)
Net activity on related-party debt	1,433	1,125
Capital expenditures	(2,029)	(2,432)
Total cash inflows (outflows)	(1,486)	1,007
Total change in cash flows	(481)	(3,937)
Ending cash, cash equivalents, and restricted cash	$1,665	$2,146

 

For the Current Year, we experienced cash flow from operations of $1.0 million compared to negative cash flow from operations of $4.9 million for the Prior Year. The $6.0 million improvement in cash flow from operations between the periods was primarily the result of decreased inventory and increased accounts payable and accrued expenses.

 

Working Capital.

 

We had a working capital deficit of $71.9 million at December 31, 2018 compared to a working capital deficit of $69.5 million at December 31, 2017. Excluding the current portion of long-term debt, we had a working capital deficit of $30.0 million at December 31, 2018 and 2017.

 

As discussed elsewhere within this “Liquidity and Capital Resources” section, the Final Arbitration Award has affected our ability to obtain working capital through financing. If the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award: (i) our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations will be materially affected, and (ii) Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws.

 

We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. There can be no assurance that LEH and its affiliates (including Jonathan Carroll) will continue to fund our working capital requirements.

 

Capital Spending.

 

Since 2015, the Nixon Facility has been undergoing a capital improvement expansion project. Capital improvements have primarily related to construction of new petroleum storage tanks to significantly increase petroleum storage capacity. However, smaller efficiency improvements have been made as well. Increased petroleum storage capacity: (i) assists with de-bottlenecking the facility, (ii) supports increased refinery throughput up to approximately 30,000 bpd, and (iii) provides an opportunity to generate additional tolling and terminaling revenue. When the expansion project is complete, petroleum storage capacity at the Nixon Facility will exceed 1.2 million bbls, an increase of more than 0.9 million bbls.

 

For the next 12 to 18 months, we expect to continue to incur capital expenditures related to facility and land improvements and completion of an unfinished petroleum storage tank. Capital spending at the Nixon Facility is being funded by working capital derived from revenue from operations and LEH and its affiliates (including Jonathan Carroll), as well as from long-term debt from Veritex that was secured in 2015 for expansion of the Nixon Facility. Unused amounts under the Veritex loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets and will be available for use once events of default associated with the Final Arbitration Award are remedied. See “Part I, Item 1. Financial Statements – Note (11) Long-Term Debt, Net” for additional disclosures related to borrowings for capital spending.

 

We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are for maintenance and those that are for expansion. We classify a capital expenditure as maintenance if it maintains capacity or throughput. A classification of expansion is used if the capital expenditure is expected to increase capacity or throughput. The distinction between maintenance and expansion is made consistent with our accounting policies and is generally a straightforward process. However, in certain circumstances the distinction can be a matter of management judgment and discretion.

 

Budgeting and approval of maintenance capital expenditures is done throughout the year on a project-by-project basis. We budget for and make maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically on a project-by-project basis in response to specific investment opportunities identified by our business segments.

 

Contractual Obligations.

 

Related-Party. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (9) Related-Party Transactions” for a summary of the agreements we have in place with related parties.

 

Long-Term Debt. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (11) Long-Term Debt, Net” for a summary of our long-term debt.

 

GEL. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Going Concern – Final Arbitration Award and Settlement Agreement” for disclosures related to the Final Arbitration Award to GEL and Settlement Agreement with GEL.

 

Supplemental Pipeline Bonds. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (19) Commitments and Contingencies – Supplemental Pipeline Bonds” for a discussion of supplemental pipeline bonding requirements.

 

Indebtedness.

 

The principal balances outstanding on our long-term debt, net (including related-party) for the periods indicated were as follow:

 

	December 31,
	2018	2017
	(in thousands)
First Term Loan Due 2034 (in default)	$22,550	$23,199
Second Term Loan Due 2034 (in default)	9,300	9,502
Notre Dame Debt (in default)	4,978	4,978
BDPL Loan Agreement (in default)	4,000	4,000
March Ingleside Note (in default)	1,283	1,169
March Carroll Note (in default)	1,147	439
June LEH Note (in default)	71	-
Capital Leases	41	-
	$43,370	$43,287
Less: Current portion of long-term debt, net	(41,364)	(39,544)
Less: Unamortized debt issue costs	(2,006)	(2,135)
	$-	$1,608

 

Principal payments on long-term debt totaled $0.9 million in the Current Year compared to $1.4 million in the Prior Year. As of the date of this Annual Report, LE and LRM were current on monthly payments under the First Term Loan Due 2034 and Second Term Loan Due 2034. There have been no payments under the Notre Dame Debt to date and no payments to Jonathan Carroll under the March Carroll Note since May 2017.

 

As described elsewhere in this Annual Report, Veritex notified obligors that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034 and Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at December 31, 2018, LE and LRM were in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the secured loan agreements. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the secured loan agreements permits Veritex to declare the amounts owed under the secured loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under the loan agreements, and/or exercise any other rights and remedies available.

 

Veritex has not accelerated or called due the secured loan agreements considering the Settlement Agreement, which Veritex must ultimately approve. Instead, Veritex has expressly reserved all its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Veritex has been working with LE and LRM and continues to be aware and party to all discussions and arrangements with GEL surrounding the Settlement. Veritex must ultimately approve the Settlement. However, if Veritex does not approve the Settlement or exercises its rights and remedies under the secured loan agreements or the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin would likely be required to seek protection under bankruptcy laws.

 

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Going Concern” and “ – Operating Risks”, as well as “Note (11) Long-Term Debt, Net” for additional disclosures related to long-term debt financial covenant violations and events of default.

 

See “Contractual Obligations – Related-Party” within the Liquidity and Capital Resources section for additional disclosures with respect to related-party indebtedness.

 

 

Off-Balance Sheet Arrangements

 

None.

 

Critical Accounting Policies

 

Long-Lived Assets.

Refinery and Facilities. Management expects to continue making improvements to the crude distillation tower based on operation needs and technological advances. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and included as operating expenses under the Amended and Restated Operating Agreement.

 

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2018. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2018. We did not record any impairment of our refinery and facilities assets for the periods presented.

Pipelines and Facilities Assets. Our pipelines and facilities are recorded at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, management performed periodic impairment testing of our pipeline and facilities assets in the fourth quarter of 2016. Upon completion of that testing, our pipeline assets were fully impaired. All pipeline transportation services to third parties have ceased, existing third-party wells along our pipeline corridor were permanently abandoned, and no new third-party wells are being drilled near our pipelines.

 

Oil and Gas Properties. Our oil and gas properties are accounted for using the full-cost method of accounting, whereby all costs associated with acquisition, exploration, and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired in 2011.

Construction in Progress. Construction in progress expenditures, which relate to construction and refurbishment activities at the Nixon Facility, are capitalized as incurred. Depreciation begins once the asset is placed in service.

Revenue Recognition.

 

We adopted the provisions of FASB ASU 2014-09, Revenue from Contracts with Customers (ASC 606), on January 1, 2018, as described below in “Recently Adopted Accounting Guidance.” Accordingly, our revenue recognition accounting policy has been revised to reflect the adoption of this standard.

 

Refinery Operations Revenue. Revenue from the sale of refined petroleum products is recognized when the product is sold to a customer in fulfillment of performance obligations. Each load of refined petroleum product is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are met when control is transferred to the customer. Control is transferred to the customer when the product has been lifted, or in cases where the product is not lifted immediately (bill and hold arrangements), when the product is added to the customer’s bulk inventory as stored at the Nixon Facility.

 

We consider a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the refined petroleum product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between sale and when payment is due is not significant. Transportation, shipping and handling costs incurred are included in cost of goods sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

 

 

Tolling and Terminaling Revenue. Revenues for tolling and terminaling include fees pursuant to: (i) tolling agreements, whereby a customer agrees to pay a certain fee per gallon or barrel for throughput volumes moving through the naphtha stabilizer unit and a fixed monthly reservation fee for use of the naphtha stabilizer unit and (ii) tank storage agreements, whereby a customer agrees to pay a certain fee per tank based on tank size over a period of time for the storage of products. We typically satisfy performance obligations for tolling and terminaling operations with the passage of time. We determine the transaction price at agreement inception based on the guaranteed minimum amount of revenue over the term of the agreement. We allocate the transaction price to the single performance obligation that exists under the agreement, and we recognize revenue in the amount for which we have a right to invoice. Generally, payment terms do not exceed thirty (30) days.

 

Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services do not provide a material right to the customer, and such services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period.

 

Inventory.

 

Our inventory primarily consists of refined petroleum products, crude oil and condensate, and chemicals. Inventory is valued at lower of cost or net realizable value with cost being determined by the average cost method, and net realizable value being determined based on estimated selling prices less any associated delivery costs. If the net realizable value of our refined petroleum products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of goods sold.

 

Asset Retirement Obligations.

 

FASB ASC guidance related to AROs requires that a liability for the discounted fair value of an ARO be recorded in the period in which incurred, and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

 

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and facility assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques.

 

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 plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, 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. We review our assumptions and estimates of future abandonment costs on an annual basis.

 

Income Taxes.

 

We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current reporting period and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.

 

 

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that some portion or all the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any NOL carryforwards. At December 31, 2018 and 2017, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of December 31, 2018 and 2017.

 

FASB ASC guidance related to income taxes also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition.

 

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (17) Income Taxes” for further information related to income taxes.

 

Recently Adopted Accounting Guidance

 

FASB issues an ASU to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. Recently adopted ASUs include:

 

ASU 2018-09, Codification Improvements. In July 2018, FASB issued ASU 2018-09. This guidance affects a wide variety of topics in the codification and represents changes to clarify, correct errors in, or make minor improvements to the codification. The amendments make the codification easier to understand and easier to apply by eliminating inconsistencies and providing clarifications. The amendments apply to all reporting entities within the scope of the affected accounting guidance. Some of the amendments in ASU 2018-09 do not require transition guidance and will be effective upon issuance. However, many of the amendments do have transition guidance with effective dates for annual periods beginning after December 15, 2018, for public business entities. Adoption of this guidance did not have a significant impact on our consolidated financial statements.

 

ASU 2014-09, Revenue from Contracts with Customers (ASC 606). We adopted this accounting pronouncement effective January 1, 2018, using a modified retrospective approach, which required us to apply the new revenue standard to: (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018. In accordance with this approach, our consolidated revenues for the periods prior to January 1, 2018 will not be revised. In November 2018, FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808). ASU 2018-18 clarifies the interaction between ASC 808 and ASC 606. Our implementation activities related to ASC 606 are complete, and we did not have any material differences in the amount or timing of revenues as a result of the adoption of ASC 606. Our largest revenue streams consist of orders received from our customers for crude-oil derived specialty products based on market prices. These revenues are recognized at a point in time upon transfer of control of the product in accordance with contractual terms. With respect to ASC 808, we are not party to a collaborative agreement with a third party.

 

New Pronouncements Issued, Not Yet Effective

 

The following are recently issued, but not yet effective, ASU’s that may influence our consolidated financial position, results of operations, or cash flows:

 

ASUs 2018-20, 2018-11, 2018-10, and 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In December 2018, FASB issued ASU 2018-20 to provide additional guidance related to sales taxes and other similar taxes collected from lessees, certain lessor costs, and recognition of variable payments for contracts with lease and non-lease components. In July 2018, FASB issued ASUs 2018-11 and 2018-10. ASU 2018-11 provides entities with relief from the costs of implementing certain aspects of ASU 2016-02 (codified as ASC 842). Specifically, under the amendments in ASU 2018-11: (i) Entities may elect not to recast the comparative periods presented when transitioning to ASC 842 (Issue 1), and (ii) Lessors may elect not to separate lease and non-lease components when certain conditions are met (Issue 2). ASU 2018-10 made 16 separate amendments to ASC 842.

 

 

For a public business entity, the amendments in ASUs 2018-11 and 2018-10 affect the amendments in ASU 2016-02, which are not yet effective, but for which early adoption upon issuance is permitted. For entities that early adopted Topic 842, the amendments are effective upon issuance of ASUs 2018-20, 2018-11 and 2018-10, and the transition requirements are the same as those in Topic 842. For entities that have not adopted Topic 842, the effective date and transition requirements will be the same as the effective date and transition requirements in Topic 842. Adoption of this guidance affects leases with a term of greater than 12-months and will result in an increase of approximately $1.0 million in our total assets and liabilities on our consolidated balance sheets. We do not expect adoption of this guidance to have a significant impact on our consolidated statements of operations.

 

ASU 2018-17, Consolidation (Topic 810). In October 2018, FASB issued ASU 2018-17. This ASU provides targeted improvements to related-party guidance for variable interest entities. In particular, indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. For entities other than private companies, the amendments in ASU 2018-17 are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

 

ASU 2018-05, Income Taxes (Topic 740).  In March 2018, FASB issued ASU 2018-05. This guidance amends SEC paragraphs in ASC 740, Income Taxes, to reflect SAB 118, which provides guidance for companies that are not able to complete their accounting for the income tax effects of the Tax Cuts and Jobs Act in the period of enactment.  This guidance also includes amendments to the XBRL Taxonomy.  For public business entities, the amendments in ASU 2018-05 are effective for fiscal years ending after December 15, 2020. Early adoption is permitted.  We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

 

Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Remainder of Page Intentionally Left Blank

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Not applicable.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Index to Financial Statements

 

Report of Independent Registered Public Accounting Firm	46
Consolidated Balance Sheets	47
Consolidated Statements of Operations	48
Consolidated Statements of Stockholders’ Equity (Deficit	49
Consolidated Statements of Cash Flows	50
Notes to Consolidated Financial Statements	51

 

 

 

Remainder of Page Intentionally Left Blank

 

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, 2018 and 2017, and the related consolidated statements of operations, stockholders’ 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, 2018 and 2017, 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 received an adverse outcome of arbitration proceedings for which a settlement has been reached, however the Company has yet to secure financing for payment of the settlement amount, is in default under secured loan agreements, has suffered recurring losses from operations 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.

 

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

 

/s/ UHY LLP _____________________

UHY LLP

Sterling Heights, Michigan April 1, 2019

  

Consolidated Balance Sheets

 

	December 31,
	2018	2017
	(in thousands except share amounts)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$14	$495
Restricted cash	49	49
Accounts receivable, net	379	1,357
Accounts receivable, related party	-	653
Prepaid expenses and other current assets	1,786	1,207
Deposits	194	129
Inventory	1,510	3,089
Refundable federal income tax	108	-
Total current assets	4,040	6,979
LONG-TERM ASSETS
Total property and equipment, net	64,697	64,597
Restricted cash, noncurrent	1,602	1,602
Surety bonds	230	230
Deferred tax assets, net	108	-
Total long-term assets	66,637	66,429
TOTAL ASSETS	$70,677	$73,408
LIABILITIES AND STOCKHOLDERS' DEFICIT
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion, in default	$34,863	35,544
Long-term debt, related party, current portion, in default	7,041	4,000
Interest payable, in default	2,939	2,135
Interest payable, related party, in default	1,534	892
Accounts payable	2,719	2,344
Accounts payable, related party	1,529	974
Asset retirement obligations, current portion	2,580	2,315
Accrued expenses and other current liabilities	1,571	1,160
Accrued arbitration award payable	21,128	27,128
Total current liabilities	75,904	76,492
LONG-TERM LIABILITIES
Deferred revenues and expenses	-	42
Long-term debt, related party, net of current portion	-	1,608
Total long-term liabilities	-	1,650
TOTAL LIABILITIES	75,904	78,142
Commitments and contingencies (Note 19)
STOCKHOLDERS' DEFICIT
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,975,514 and 10,925,513
shares issued at December 31, 2018 and 2017, respectively)	110	109
Additional paid-in capital	36,936	36,907
Accumulated deficit	(42,273)	(41,750)
TOTAL STOCKHOLDERS' DEFICIT	(5,227)	(4,734)
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$70,677	$73,408

 

See accompanying notes to consolidated financial statements. 

 

Consolidated Statements of Operations

 

	Twelve Months Ended December 31,
	2018	2017
	(in thousands, except share and per-share amounts)
REVENUE FROM OPERATIONS
Refinery operations	$337,038	$255,547
Tolling and terminaling	3,723	2,902
Total revenue from operations	340,761	258,449
COST OF GOODS SOLD
Crude oil, fuel use, and chemicals	322,297	239,740
Other conversion costs	9,639	8,693
Total cost of goods sold	331,936	248,433
Gross Profit	8,825	10,016
COST OF OPERATIONS
LEH operating fee	614	817
Other operating expenses	180	228
Arbitration award and associated fees	-	24,339
General and administrative expenses	3,272	4,022
Depletion, depreciation and amortization	1,933	1,810
Impairment of assets	-	303
Bad debt expense	-	81
Accretion of asset retirement obligations	266	287
Total cost of operations	6,265	31,887
Income (loss) from operations	2,560	(21,871)
OTHER INCOME (EXPENSE)
Easement, interest and other income	20	479
Interest and other expense	(3,363)	(2,770)
Gain on disposal of property	-	1,834
Total other income (expense)	(3,343)	(457)
Loss before income taxes	(783)	(22,328)
Income tax benefit	260	-
Net loss	$(523)	$(22,328)
Loss per common share:
Basic	$(0.05)	$(2.09)
Diluted	$(0.05)	$(2.09)
Weighted average number of common shares outstanding:
Basic	10,935,787	10,689,615
Diluted	10,935,787	10,689,615
See accompanying notes to consolidated financial statements.

 

Consolidated Statements of Stockholders’ Equity (Deficit)

 

	(in thousands except share amounts)
			Additional				Total
	Common Stock		Paid-In	Accumulated	Treasury Stock		Stockholders’
	Shares Issued	Par Value	Capital	Deficit	Shares	Cost	Equity (Deficit)
Balance at December 31, 2016	10,624,714	$106	$36,819	$(19,422)	(150,000)	$(800)	$16,703
Common stock issued for services	300,799	3	88		150,000	800	891
Net loss	-	-	-	(22,328)	-	-	(22,328)
Balance at December 31, 2017	10,925,513	$109	$36,907	$(41,750)	-	$-	$(4,734)
Common stock issued for services	50,001	1	29		-	-	30
Net loss	-	-	-	(523)	-	-	(523)
Balance at December 31, 2018	10,975,514	$110	$36,936	$(42,273)	-	$-	$(5,227)