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, 2019

 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	z77002
(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 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.

Large accelerated filer	[ ]	Accelerated filer	[ ]
Non-accelerated filer	[ ]	Smaller reporting company	[√ ]
		Emerging growth company	[ ]

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 $2,100,065 as of June 28, 2019 (the last trading day of the registrant’s most recently completed second fiscal quarter) based on the number of shares of common stock held by non-affiliates and the last reported sale price of the registrant's common stock on June 28, 2019.

Number of shares of common stock, par value $0.01 per share, outstanding at March 30, 2020: 12,327,365

Table of Contents

PART I		7
ITEM 1.	BUSINESS	7
ITEM 1A.	RISK FACTORS	13
ITEM 1B.	UNRESOLVED STAFF COMMENTS	24
ITEM 2.	PROPERTIES	24
ITEM 3.	LEGAL PROCEEDINGS	24
ITEM 4.	MINE SAFETY DISCLOSURES	24
PART II		25
ITEM 5.	MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	25
ITEM 6.	SELECTED FINANCIAL DATA	25
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	26
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	37
	Report of Independent Registered Public Accounting Firm	37
	Consolidated Balance Sheets	38
	Consolidated Statements of Operations	39
	Consolidated Statements of Stockholders’ Equity (Deficit)	40
	Consolidated Statements of Cash Flows	41
	Notes to Consolidated Financial Statements	42
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	66
ITEM 9A.	CONTROLS AND PROCEDURES	66
ITEM 9B.	OTHER INFORMATION	68
PART III		69
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	69
ITEM 11.	EXECUTIVE COMPENSATION	74
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	76
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	77
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	77
PART IV		78
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	78
ITEM 16.	FORM 10-K SUMMARY	78
SIGNATURES		83

Glossary of Terms

Glossary of Terms

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

Affiliate. Refers, either individually or collectively, to certain related parties including, Jonathan Carroll, Chairman and Chief Executive Officer of Blue Dolphin, and his affiliates (including C&C, Ingleside, and Lazarus Capital) and/or LEH and its affiliates (including Lazarus Midstream, LMT, and LTRI). Together, Jonathan Carroll and LEH own approximately 82% of Blue Dolphin’s Common Stock. AMT. Alternative Minimum Tax. Amended Pilot Line of Credit. Line of Credit Agreement dated May 3, 2019, between Pilot and NPS and subsequently amended on May 9, 2019 and May 10, 2019 and September 3, 2019, the last amendment being Amendment No. 1; line of credit amount is $13.0 million. Amended and Restated Operating Agreement. Affiliate agreement dated April 1, 2017 between Blue Dolphin, LEH, and LE governing LEH’s operation and management of Blue Dolphin’s assets; expires on April 1, 2020; the Board plans to extend the agreement. ARO. Asset retirement obligations. ASU. Accounting Standards Update. AGO. Atmospheric gas oil, which is the heaviest product boiled by a crude distillation tower operating at atmospheric pressure. This fraction ordinarily sells as distillate fuel oil, either in pure form or blended with cracked stocks. Certain ethylene plants, called heavy oil crackers, can take AGO as feedstock. bbl. Barrel; a unit of volume equal to 42 U.S. gallons. BDPC. Blue Dolphin Petroleum Company, a wholly owned subsidiary of Blue Dolphin. BDPL. Blue Dolphin Pipe Line Company, a wholly owned subsidiary of Blue Dolphin. BDSC. Blue Dolphin Services Co., a wholly owned subsidiary of Blue Dolphin. bpd. Barrel per day;a measure of the bbls of daily output produced in a refinery or transported through a pipeline. Board. Board of Directors of Blue Dolphin Energy Company. BOEM. Bureau of Ocean Energy Management. BSEE. Bureau of Safety and Environmental Enforcement. C&C. Carroll & Company Financial Holdings, L.P., an affiliate of Jonathan Carroll. Capacity Utilization Rate. A percentage measure that indicates the amount of available capacity that is being used in a refinery or transported through a pipeline. With respect to the crude distillation tower, the rate is calculated by dividing total refinery throughput or total refinery production on a bpd basis by the total capacity of the crude distillation tower (currently 15,000 bpd). CAA. Clean Air Act. CERLA. Comprehensive Environmental Response, Compensation, and Liability Act of 1980. CIP. Construction in progress. COVID-19. An infectious disease first identified in 2019 in Wuhan, the capital of China's Hubei province; the disease has since spread globally, resulting in the ongoing 2019-2020 coronavirus pandemic. CWA. Clean Water Act. Common Stock. Blue Dolphin common stock, par value $0.01 per share. Complexity. A numerical score that denotes, for a given refinery, the extent, capability, and capital intensity of the refining processes downstream of the crude distillation tower. Refinery complexities range from the relatively simple crude distillation tower (“topping unit”), which has a complexity of 1.0, to the more complex deep conversion (“coking”) refineries, which have a complexity of 12.0. Condensate. Liquid hydrocarbons that are produced in conjunction with natural gas. Although condensate is sometimes like crude oil, it is usually lighter. Cost of Goods Sold. Reflects the cost of crude oil and condensate, fuel use, and chemicals. Crude distillation tower. A tall column-like vessel in which crude oil and condensate is heated and its vaporized components are distilled by means of distillation trays. This process turns crude oil and other inputs into intermediate and finished petroleum products. (Commonly referred to as a crude distillation unit or an atmospheric distillation unit.) Crude oil. A mixture of thousands of chemicals and compounds, primarily hydrocarbons. Crude oil quality is measured in terms of density (light to heavy) and sulfur content (sweet to sour). Crude oil must be broken down into its various components by distillation before these chemicals and compounds can be used as fuels or converted to more valuable products. Depropanizer unit. A distillation column that is used to isolate propane from a mixture containing butane and other heavy components. Distillates. The result of crude distillation and therefore any refined oil product. Distillate is more commonly used as an abbreviated form of middle distillate. There are mainly four (4) types of distillates: (i) very light oils or light distillates (such as naphtha), (ii) light oils or middle distillates (such as our jet fuel), (iii) medium oils, and (iv) heavy oils (such as our low- sulfur diesel and HOBM, reduced crude, and AGO). Distillation. The first step in the refining process whereby crude oil and condensate is heated at atmospheric pressure in the base of a distillation tower. As the temperature increases, the various compounds vaporize in succession at their various boiling points and then rise to prescribed levels within the tower per their densities, from lightest to heaviest. They then condense in distillation trays and are drawn off individually for further refining. Distillation is also used at other points in the refining process to remove impurities. Downtime. Scheduled and/or unscheduled periods in which the crude distillation tower is not operating. Downtime may occur for a variety of reasons, including bad weather, power failures, and preventive maintenance. EIA. Energy Information Administration. EPA. Environmental Protection Agency. Eagle Ford Shale. A hydrocarbon-producing geological formation extending across South Texas from the Mexican border into East Texas. Exchange Act. Securities Exchange Act of 1934, as amended. FASB. Financial Accounting Standards Board. FDIC. Federal Deposit Insurance Corporation. Feedstocks. Crude oil and other hydrocarbons, such as condensate and/or intermediate products, that are used as basic input materials in a refining process. Feedstocks are transformed into one or more finished products. Finished petroleum products. Materials or products which have received the final increments of value through processing operations, and which are being held in inventory for delivery, sale, or use. GEL. GEL Tex Marketing, LLC, a Delaware limited liablity company and an affiliate of Genesis Energy, LLC. GEL Final Arbitration Award. Damages and attorney fees and related expenses awarded to GEL by an arbitrator on August 11, 2017. GEL Interim Payments. Cash payments of $0.5 million at the end of each calendar month by the Lazarus Parties to GEL until the GEL Settlement Payment was made. GEL Settlement. When all conditions of the GEL Settlement Agreement were met by the Lazarus Parties under the GEL Settlement Agreement, and whereby GEL and the Lazarus Parties agreed to mutually release all claims against each other and to file a stipulation of dismissal with prejudice in connection with arbitration proceedings between LE and GEL related to a contractual dispute involving a crude oil supply and throughput services agreement, each between LE and GEL dated August 12, 2011. GEL Settlement Agreement. Settlement Agreement dated July 20, 2018, between the Lazarus Parties and GEL outlining the terms and conditions for a settlement, including: (i) the GEL Settlement Payment by the GEL Settlement Date and (ii) GEL Interim Payments. GEL Settlement Date. The effective date of the GEL Settlement. GEL Settlement Payment. A lump sum cash payment of $10.0 million as paid by the Lazarus Parties to GEL under the GEL Settlement Agreement.

Glossary of Terms

Gross Profit.Calculated as total revenue less cost of goods sold; reflected as a dollar ($) amount. HOBM. Heavy oil-based mud blendstock; see also “distillates.” HUBZone. Historically Underutilized Business Zones program established by the SBA to help small businesses in both urban and rural communities. IBLA. Interior Board of Land Appeals. INC. Incident of Noncompliance issued by BOEM and/or BSEE. Ingleside. Ingleside Crude, LLC, an affiliate of Jonathan Carroll. Intermediate petroleum products. A petroleum product that might require further processing before it is saleable to the ultimate consumer. This further processing might be done by the producer or by another processor. Thus, an intermediate petroleum product might be a final product for one company and an input for another company that will process it further. IRC Section 382. Title 26, Internal Revenue Code, Subtitle A – Income Taxes, Subchapter C – Corporate Distributions and Adjustments, Part V Carryovers, § 382. Limits NOL carryforwards and certain built-in losses following ownership change. IRS. Internal Revenue Service. Jet fuel. A high-quality kerosene product primarily used in aviation. Kerosene-type jet fuel (including Jet A and Jet A-1) has a carbon number distribution between 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between 5 and 15 carbon atoms per molecule. Lazarus Capital. Lazarus Capital, LLC, an affiliate of Jonathan Carroll. Lazarus Midstream. Lazarus Midstream Partners, L.P., an affiliate of LEH. Lazarus Parties. Blue Dolphin, C&C, NPS,LE, LEH, and Jonathan Carroll. LE. Lazarus Energy, LLC, a wholly owned subsidiary of Blue Dolphin. LEH. Lazarus Energy Holdings, LLC, an affiliate of Jonathan Carroll and controlling shareholder of Blue Dolphin. LEH Operating Fee. A management fee paid to LEH under the Amended and Restated Operating Agreement; calculated as 5% of Blue Dolphin’s incurred direct operating expenses; previously reflected within refinery operating expenses in our consolidated statements of operations. Leasehold interest. The interest of a lessee under an oil and gas lease. Light crude. A liquid petroleum that has a low density and flows freely at room temperature. It has a low viscosity, low specific gravity, and a high American Petroleum Institute gravity due to the presence of a high proportion of light hydrocarbon fractions. LMT. Lazarus Marine Terminal I, LLC, an affiliate of LEH. LRM. Lazarus Refining & Marketing, LLC, a wholly owned subsidiary of Blue Dolphin. LTRI. Lazarus Texas Refinery I, an affiliate of LEH. NAAQS. National Ambient Air Quality Standards. Naphtha. A refined or partly refined light distillate fraction of crude oil. Blended further or mixed with other materials it can make high-grade motor gasoline or jet fuel. It is also a generic term applied to the lightest and most volatile petroleum fractions. Natural Gas. A naturally occurring hydrocarbon gas mixture consisting primarily of methane, but commonly including varying amounts of other higher alkanes, and sometimes a small percentage of carbon dioxide, nitrogen, hydrogen sulfide, or helium. NPS. Nixon Product Storage, LLC, a wholly owned subsidiary of Blue Dolphin. NOL. Net operating losses. NSR/PSD. New Source Review/Prevention of Significant Deterioration. OPA 90. Oil Pollution Act of 1990. Operating Days. Represents the number of days in a period in which the crude distillation tower operated. Operating days is calculated by subtracting downtime in a period from calendar days in the same period. OSHA. Occupational Safety and Health Administration. OSRO. Oil Spill Response Organization. Other conversion costs. Represents the combination of direct labor costs and manufacturing overhead costs. These are the costs that are necessary to convert our raw materials into refined products. Other Operating Expenses. Represents costs associated with our natural gas processing, treating, and redelivery facility, as well as our pipeline assets and leasehold interests in oil and gas properties. PCAOB. Public Company Accounting Oversight Board. Petroleum. A naturally occurring flammable liquid consisting of a complex mixture of hydrocarbons of various molecular weights and other liquid organic compounds. The name petroleum covers both the naturally occurring unprocessed crude oils and petroleum products that are made up of refined crude oil. PHMSA. Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation. Pilot. Pilot Travel Centers LLC, a Delaware limited liability company.
Preferred Stock. Blue Dolphin preferred stock, par value $0.10 per share. Product Slate. Represents type and quality of products produced. Propane. A by-product of natural gas processing and petroleum refining. Propane is one of a group of liquified petroleum gases. Others include butane, propylene, butadiene, butylene, isobutylene and mixtures thereof. Refined Products. Hydrocarbon compounds, such as jet fuel and residual fuel, that are produced by a refinery. Refinery. Within the oil and gas industry, a refinery is an industrial processing plant where crude oil, condensate, and intermediate feeds are separated and transformed into petroleum products. Refining Gross Profit per Bbl. Calculated as refinery operations revenue less total cost of goods sold divided by the volume, in bbls, of refined products sold during the period; reflected as a dollar ($) amount per bbl. RCRA. Federal Resource Conservation and Recovery Act. RFS2. Second Renewable Fuels Standard. ROU. Right-of-use. SEC. Securities and Exchange Commission. Segment Contribution Margin. For our refinery operations and tolling and terminaling business segments, represents net revenues (excluding intercompany fees and sales) attributable to the respective business segment less associated intercompany fees and sales less associated operation costs and expenses. SEMS. Safety and Environmental Management System. Sour crude. Crude oil containing sulfur content of more than 0.5%. Stabilizer unit. A distillation column intended to remove the lighter boiling compounds, such as butane or propane, from a product. Sweet crude. Crude oil containing sulfur content of less than 0.5%. Sulfur. Present at various levels of concentration in many hydrocarbon deposits, such as petroleum, coal, or natural gas. Also, produced as a by-product of removing sulfur-containing contaminants from natural gas and petroleum. Some of the most commonly used hydrocarbon deposits are categorized per their sulfur content, with lower sulfur fuels usually selling at a higher, or premium, price and higher sulfur fuels selling at a lower, or discounted, price. Topping unit. A type of petroleum refinery that engages in only the first step of the refining process -- crude distillation. A topping unit uses atmospheric distillation to separate crude oil and condensate into constituent petroleum products. A topping unit has a refinery complexity range of 1.0 to 2.0.

Glossary of Terms

Throughput. The volume processed through a unit or a refinery or transported through a pipeline. Total Refinery Production. Refers to the volume processed as output through the crude distillation tower. Refinery production includes finished petroleum products, such as jet fuel, and intermediate petroleum products, such as naphtha, HOBM and AGO. Total Refinery Throughput. Refers to the volume processed as input through the crude distillation tower. Refinery throughput includes crude oil and condensate and other feedstocks. TMT. Texas margins tax; a form of business tax imposed on an entity’s gross profit rather than on its net income. Turnaround. Scheduled large-scale maintenance activity wherein an entire process unit is taken offline for a week or more for comprehensive revamp and renewal. USACOE. U.S. Army Corps of Engineers. USDA. U.S. Department of Agriculture. U.S. GAAP. Accounting principles generally accepted in the United States of America. Veritex. Veritex Community Bank, successor in interest to Sovereign Bank by merger. WSJ Prime Rate. A measure of the U.S. prime rate as defined by the Wall Street Journal.
XBRL. eXtensible Business Reporting Language. Yield. The percentage of refined products that is produced from crude oil and other feedstocks.

Important Information Regarding Forward Looking Statements

Important Information Regarding Forward-Looking Statements

This report (including information incorporated by reference) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act, including, but not limited to, those under “Item 1. Business,” “Item 1A. Risk Factors,” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” All statements other than statements of historical fact, including without limitation statements regarding expectations regarding revenue, cash flows, capital expenditures, and other financial items, our business strategy, goals and expectations concerning our market position, future operations and profitability, are forward-looking statements. Forward-looking statements may be identified by use of the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will,” “would” and similar terms and phrases. Although we believe our assumptions concerning future events are reasonable, several risks, uncertainties, and other factors could cause actual results and trends to differ materially from those projected, including but not limited to:

Business and Industry

● 

Our going concern status.

● 

Inadequate liquidity to sustain operations due to defaults under our secured loan agreements, historic net losses, and working capital deficits.

● 

Substantial debt in the current portion of long-term debt, which is currently in default.

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Ability to regain compliance with the terms of our outstanding indebtedness.

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Increased costs of capital or a reduction in the availability of credit.

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Affiliate common stock ownership and transactions that could cause conflicts of interest.

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Operational hazards inherent in refining and natural gas processing operations and in transporting and storing crude oil and condensate and refined products.

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Geographic concentration of our assets, creating significant exposure to regional economy risks and other conditions.

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Geographic concentration of our refining operations and customers within the Eagle Ford Shale.

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Competition from companies having greater financial and other resources.

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Federal, state, and local environmental, economic, health and safety, energy and other policies and regulations, including those related to climate change, and any changes therein, and any legal and regulatory investigations, delays in obtaining necessary approvals and permits, compliance costs or other factors beyond our control.

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

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Changes in insurance markets impacting costs and the level and types of coverage available.

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NOL carryforwards to offset future taxable income for U.S. federal income tax purposes that are subject to limitation.

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Direct or indirect effects on our business resulting from actual or threatened terrorist or activist incidents, cyber-security breaches, or acts of war.

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Outbreak of COVID-19, or an outbreak of another highly infectious or contagious disease, could adversely impact our business, financial condition, and results of operations.

Refinery and Tolling and Terminaling Operations

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Timing and extent of changes in commodity prices and demand for refined products.

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Availability and costs of crude oil and other feedstocks.

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Price volatility of fuel and utility services to operate the Nixon facility.

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Disruptions due to equipment interruption or failure at the Nixon facility.

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Changes in our cash flow from operations and working capital requirements, shortfalls of which Affiliates may not fund.

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Ability to remain in compliance with the terms of our outstanding indebtedness.

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Key personnel loss, labor relations, and workplace safety.

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Loss of market share by and a material change in profitability of our key customers.

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Contract cancellation, non-renewal, or failure to perform by those in our supply and distribution chains, and the ability to replace such contracts and/or customers.

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Changes in the cost or availability of third-party vessels, pipelines, trucks, and other means of delivering and transporting crude oil and condensate, feedstocks, and refined products.

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Sourcing of a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale.

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Geographic concentration of our refining operations and customers within the Eagle Ford Shale.

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Weather conditions, hurricanes or other natural disasters affecting operations by us or our key customers or the areas in which our customers operate.

Pipeline and Facilities and Oil and Gas Assets

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Assessment of civil penalties by BOEM for failure to satisfy orders to increase supplemental pipeline bonds within the time period prescribed.

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Assessment of civil penalties by BSEE for failure to decommission platform and pipeline assets within the time period prescribed.

Common Stock

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Our stock price may decline due to sales of shares by Affiliates.

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Issuance of additional shares of Common Stock and Preferred Stock may significantly dilute the equity ownership of current holders.

See also the risk factors described in greater detail under “Item 1A.” of this report and our other filings with the SEC.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to revise or update any forward-looking statements as a result of new information, future events, or otherwise.

Business

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

Part I should be read in conjunction with “Part II, Item 7.” and “Part II, Item 8.”

PART I

ITEM 1. 

BUSINESS

Overview

Blue Dolphin is an independent downstream energy company operating in the Gulf Coast region of the United States. Our subsidiaries operate a light sweet-crude, 15,000-bpd crude distillation tower with approximately 1.2 million bbls of petroleum storage tank capacity in Nixon, Texas. Blue Dolphin was formed in 1986 as a Delaware corporation and is traded on the OTCQX under the ticker symbol “BDCO”.

Our assets are primarily organized in two segments: refinery operations (owned by LE) and tolling and terminaling services (owned by LRM and NPS). Subsidiaries that are reflected in corporate and other include BDPL (inactive pipeline and facilities assets), BDPC (inactive leasehold interests in oil and gas wells), and BDSC (administrative services). See "Item 1.,” “Item 2.,” and “Note (4)” to our consolidated financial statements for more information related to our business segments and properties.

Affiliates

Affiliates control approximately 82% of the voting power of our Common Stock. An Affiliate operates and manages all Blue Dolphin properties and funds working capital requirements during periods of working capital deficits, and an Affiliate is a significant customer of our refined products. Blue Dolphin and certain of its subsidiaries are currently parties to a variety of agreements with Affiliates. See “Item 1A.” and “Note (3)” to our consolidated financial statements for additional disclosures related to Affiliate risk factors, Affiliate agreements and arrangements, and risks associated with working capital deficits.

Going Concern

See “Item 1A.” and “Note (1)” to our consolidated financial statements regarding going concern factors and associated risks.

Operating Risks

See “Note (1)” to our consolidated financial statements regarding factors that have negatively impacted our business plan execution.

Refinery Operations

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

Property	Key Products Handled	Operating Subsidiary	Location
Nixon facility ● Crude distillation tower (15,000 bpd) ● Petroleum storage tanks ● Loading and unloading facilities ● Land (56 acres)	Crude Oil Refined Products	LE	Nixon, Texas

See below under “Refinery Operations Process Summary” for an overview diagram of our refinery operations.

Capital Improvement Expansion Project. Since 2015, the Nixon facility has been undergoing a capital improvement expansion project. Refinery operations capital improvements have primarily related to construction of new petroleum storage tanks. However, smaller efficiency improvements have been made as well. In the short-term, increased petroleum storage capacity has helped with de-bottlenecking the refinery. In the long-term, additional petroleum storage capacity will allow for increased refinery throughput of up to approximately 30,000 bpd.

7

Business

Crude Oil and Condensate Supply.  Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. We have a long-term crude supply agreement in place with Pilot. Under the initial term of the crude supply agreement, Pilot will sell us approximately 24.8 million net bbls of crude oil. Thereafter, the crude supply agreement will continue on a one-year evergreen basis. Pilot may terminate the crude supply agreement at any time by providing us 60 days prior written notice. We may terminate the agreement upon the expiration of the initial term or at any time during a renewal term by giving Pilot 60 days prior written notice.

Pilot also stores crude oil at the Nixon facility under a terminal services agreement. Under the terminal services agreement, Pilot stores crude oil at the Nixon facility at a specified rate per bbl of the storage tank’s shell capacity. The terminal services agreement has an initial term that expires April 30, 2020. Thereafter, the terminal services agreement will continue on a one-year evergreen basis. Either party may terminate the terminal services agreement by providing the other party 60 days prior written notice. However, the terminal services agreement will automatically terminate upon expiration or termination of the crude supply agreement.

Our financial health could be adversely affected by defaults under our secured loan agreements, historic net losses, and working capital deficits, which could impact our ability to acquire crude oil and condensate. A failure to acquire crude oil and condensate when needed will have a material effect on our business results and operations. See “Item 1A.” for risks associated with crude supply.

Refinery Operations 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 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 outut of refined products.

A regional electric cooperative supplies electrical power to our facility in Nixon, Texas. Fuel gas is produced as a by-product at the Nixon refinery and 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.

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

The Nixon refinery’s product slate is moderately adjusted based on market demand. We currently produce a single finished product – jet fuel – and several intermediate products, including naphtha, HOBM, and AGO. Our jet fuel is sold to an Affiliate, which is HUBZone certified. Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing. See “Note (3)” and “Note (16)” to our consolidated financial statements for additional disclosures related to Affiliates arrangements and transactions.

Customers.Customers for our refined products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers, including month-to-month, six months, and up to one-year terms. Certain of our contracts require our customers to prepay and us to sell fixed quantities and/or minimum quantities of finished and intermediate petroleum products. Many of these arrangements are subject to periodic renegotiation on a forward-looking basis, which could result in higher or lower relative prices on future sales of our refined products. See “Item 1A.” and “Note (5)” to our consolidated financial statements for disclosures related to concentration of risk associated with significant customers.

8

Business

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

Safety and Downtime. Our refinery operations are operated in a manner consistent with industry safe practices and standards. These operations are subject to regulations under OSHA, the EPA, and comparable state and local requirements. Together, these regulations are designed for personnel safety, process safety management, and risk management, as well as to prevent or minimize the probability and consequences of an accidental release of toxic, reactive, flammable, or explosive chemicals. Storage tanks used for refinery operations are designed for crude oil and condensate and refined products, and most are equipped with appropriate controls that minimize emissions and promote safety. Our refinery operations have response and control plans, spill prevention and other programs to respond to emergencies. See “Government Regulations” below for specific federal, state and local regulations for which our refinery operations are subject.

The Nixon refinery periodically experiences planned and unplanned temporary shutdowns. Unplanned shutdowns can occur for a variety of reasons, including voluntary regulatory compliance measures, cessation or suspension by regulatory authorities, or disabled equipment. However, in Texas the most typically reason is excessive heat or power outages from high winds and thunderstorms. Planned turnarounds are used to repair, restore, refurbish, or replace refinery equipment. Refineries typically undergo a major turnaround every three to five years. Since the Nixon refinery was placed back in service in 2012 (commonly referred to as “recommissioning”), turnarounds are needed more frequently for unanticipated maintenance or repairs.

We are particularly vulnerable to disruptions in our operations because all our refining operations are conducted at a single facility. Any scheduled or unscheduled downtime will result in lost margin opportunity, potential increased maintenance expense, and a reduction of refined products inventory, which could reduce our ability to meet our payment obligations. See “Item 1A.” for risks sociated with Nixon refinery downtime.

Tolling and Terminaling Operations

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

Property	Key Products Handled	Operating Subsidiary	Location
Nixon facility ● Petroleum storage tanks ● Loading and unloading facilities	Crude Oil Refined Products	LRM, NPS	Nixon, Texas

Capital Improvement Expansion Project. As previously noted, the Nixon facility has been undergoing a capital improvement expansion project since 2015. Tolling and terminaling capital improvements have primarily related to construction of new petroleum storage tanks to significantly increase petroleum storage capacity. Increased petroleum storage capacity will provide an opportunity to generate additional tolling and terminaling revenue.

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

Operations Safety. Our tolling and terminal operations are operated in a manner consistent with industry safe practices and standards. These operations are subject to regulations under OSHA and comparable state and local regulations. Storage tanks used for terminal operations are designed for crude oil and condensate and refined products, and most are equipped with appropriate controls that minimize emissions and promote safety. Our terminal operations have response and control plans, spill prevention and other programs to respond to emergencies. See “Government Regulations” below for specific federal, state and local regulations for which our tolling and terminaling operations are subject.

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Business

Inactive Operations

We own certain other pipeline and facilities assets and have leasehold interests in oil and gas properties. These assets, which are shown below and included in corporate and other, are not operational and are fully impaired.

Property	Operating Subsidiary	Location
Freeport facility ● Crude oil and natural gas separation and dehydration ● Natural gas processing, treating, and redelivery ● Vapor recovery unit ● Two onshore pipelines ● Land (162 acres)	BDPL	Freeport, Texas
Offshore Pipelines (Trunk Line and Lateral Lines)	BDPL	Gulf of Mexico
Oil and Gas Leasehold Interests	BDPC	Gulf of Mexico

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, 2019 and 2018. See “Item 1A.” and “Note (16)” to our consolidated financial statements related to idle iron decommissioning requirements and related risks.

Pipeline and Facilities Safety.

Although our pipeline and facility assets are inactive, they require upkeep and maintenance and are subject to safety regulations under OSHA, PHMSA, BOEM, BSEE, and comparable state and local regulations. We have response and control plans, spill prevention and other programs to respond to emergencies related to these assets. See “Government Regulations” below for specific federal, state and local regulations for which our pipeline and facilities assets are subject.

Personnel

We have no employees. We rely on an Affiliate to manage our facilities pursuant to the Amended and Restated Operating Agreement. Services under the Amended and Restated Operating Agreement include personnel serving in a variety of capacities, including, but not limited to corporate executives, operations and maintenance, environmental, health and safety, and administrative and professional services. At December 31, 2019, the Affiliate had a total of 216 employees, 165 full-time and 51 part-time. No personnel were covered by collective bargaining agreements. See “Note (3)” to our consolidated financial statements for additional disclosures related to Affiliate arrangements.

Insurance and Risk Management

Our operations are subject to significant hazards and risks inherent in crude oil and condensate refining operations, as well as the transportation and storage of crude oil and condensate and refined products. We have property damage 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 coverages are supported by safety and other risk management programs.

Intellectual Property

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

Website Access to Reports and Other Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other public filings with the SEC are available, free of charge, on our website (http://www.blue-dolphin-energy.com) as soon as reasonably practical after we file them with, or furnish them to, the SEC. Information contained on our website is not part of this report. You may also access these reports on the SEC’s website at http://www.sec.gov.

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Business

Government Regulations

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

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

The EPA has undertaken significant regulatory initiatives under authority of the Clean Air Act’s NSR/PSD program to further reduce emissions of volatile organic compounds, nitrogen oxides, sulfur dioxide, and particulate matter. These regulatory initiatives have been targeted at industries with large manufacturing facilities that are significant sources of emissions, such as refining, paper and pulp, and electric power generating industries. The basic premise of these initiatives is the EPA’s assertion that many of these industrial establishments have modified or expanded their operations over time without complying with NSR/PSD regulations adopted by the EPA that require permits and new emission controls in connection with any significant facility modifications or expansions that can result in emission increases above certain thresholds. As part of this ongoing NSR/PSD regulatory initiative, the EPA has consent decrees with several refiners that require refiners to make significant capital expenditures to install emissions control equipment at selected facilities. We have not been selected by the EPA to enter a consent decree. If selected, as a small refiner we do not expect any additional requirements to have a material impact on our financial position, results of operations, or liquidity.

The EPA strengthened the NAAQS for ground-level ozone to 70 parts per billion in 2015 from the 75-parts per billion level set in 2008. To implement the revised ozone NAAQS, all states will need to review their existing air quality management infrastructure State Implementation Plan for ozone and ensure it is appropriate and adequate. Where areas remain in ozone non-attainment, or come into ozone non-attainment as a result of the revised NAAQS, it is likely that additional planning and control obligations will be required. States may impose additional emissions control requirements on stationary sources, changes in fuels specifications, and changes in fuels mix and mobile source emissions controls. The ongoing and potential future requirements imposed by states to meet the ozone NAAQS could have direct impacts on terminaling facilities through additional requirements and increased permitting costs and could have indirect impacts through changing or decreasing fuel demand.

The Energy Independence and Security Act of 2007 created RFS2 requiring the total volume of renewable transportation fuels (including ethanol and advanced biofuels) sold or introduced in the U.S. to reach 36.0 billion gallons by 2022. We applied for an extension of the temporary exemption afforded small refineries through December 31, 2010. The EPA granted the Nixon refinery a small refinery exemption from RFS2 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 RFS2.

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

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

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Business

We generate petroleum product wastes, solid wastes, and ordinary industrial wastes, such as from paints and solvents, that are regulated under RCRA and comparable state statues. We are not currently required to comply with a substantial portion of the RCRA requirements because we are considered small quantity generators of hazardous wastes by the EPA and state regulations. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. The Hazardous Waste Generator Improvement Rule of the EPA provides some additional flexibility for small generators but also increases certain recordkeeping and administrative burdens. Several states are now in the process of adopting this rule. Any additional changes in the regulations could increase our capital and operating costs.

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

Water Pollution Regulations.Our operations can result in the discharge of pollutants, including chemical components of crude oil and refined products, into federal and state waters. The CWA prohibits the discharge of pollutants into U.S. waters except as authorized by the terms of a permit issued by the EPA or a state agency with delegated authority. The transportation and storage of crude oil and refined products over and adjacent to water involves risks and subjects us to the provisions of the CWA, OPA 90, and related state requirements.

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

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

Offshore “Idle Iron” Decommissioning Regulations.In 2018 BSEE updated its earlier 2010 guidance and regulations on decommissioning that mandates lessees and rights-of-way holders permanently abandon and/or remove platforms and other structures when no longer useful for operations. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the minimum bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM.

We are required by BOEM to: (i) maintain acceptable financial assurance (pipeline bonds) for the decommissioning of our assets offshore in federal waters and (ii) decommission these assets following a certain period of inactivity. As of December 31, 2019, we maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM. As of December 31, 2019, we maintained $2.6 million in AROs related to abandonment of these assets. See “Item 1A.,” “Note (12),” and “Note (16)” to our consolidated financial statements for additional disclosures related to idle iron decommissioning requirements for our pipelines and facilities assets and related risks.

Health, Safety and Maintenance

We are subject to the requirements of OSHA and other federal and state agencies that address employee health and safety. In general, we believe current expenditures are fulfilling the OSHA requirements and protecting the health and safety of our employees. Based on new regulatory developments, we may increase expenditures in the future to comply with higher industry and regulatory safety standards. However, such increases in our expenditures, and the extent to which they might be offset, cannot be estimated at this time.

BSEE also requires offshore operators to employ a SEMS plan.  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. We have a SEMS program in place.

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Risk Factors

ITEM 1A.  RISK FACTORS

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

A. 

Risks Related to Our Business and Industry

A1. 

Management has determined that there is, and the report of our independent registered public accounting firm expresses, substantial doubt about our ability to continue as a going concern.

Management has determined that conditions exist that raise substantial doubt about our ability to continue as a going concern due to defaults under our secured loan agreements, historic net losses, and working capital deficits. 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 on sustained positive operating margins and working capital to sustain operations, including the purchase of crude oil and condensate and payments on long-term debt.  If we are unable to achieve these goals, our business would be jeopardized, and we may not be able to continue. If we are unable to make required debt payments, we would likely have to consider other options, such as selling assets, raising additional debt or equity capital, cutting costs or otherwise reducing our cash requirements, or negotiating with our creditors to restructure our applicable obligations.

A2. 

Inadequate liquidity to sustain operations due to defaults under our secured loan agreements, historic net losses, and working capital deficits, any of which could have a material adverse effect on us.

We currently rely on revenue from operations, Affiliates, 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 short-term 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. The Amended Pilot Line of Credit will mature in May 2020. Our liquidity will affect our ability to satisfy any of these needs.

We had a working capital deficit of $59.4 million and $71.9 million at December 31, 2019 and 2018, respectively. Excluding the current portion of long-term debt, we had a working capital deficit of $19.6 million and $30.0 million at December 31, 2019 and 2018, respectively. We had cash and cash equivalents and restricted cash (current portion) of $0.07 million and $0.05 million, respectively, at December 31, 2019. Comparatively, we had cash and cash equivalents and restricted cash (current portion) of $0.01 million and $0.05 million, respectively, at December 31, 2018.

While we believe that we can fund our operations through revenue from operations and Affiliate financing, we may not be able to, among other things, (i) maintain our current general and administrative spending levels; (ii) fund certain obligations as they become due; and (iii) respond to competitive pressures or unanticipated capital requirements. We cannot provide any assurance that financing will be available to us in the future on acceptable terms.

A3. 

Defaults under our secured loan agreements could have a material adverse effect on our business, financial condition, and results of operations and materially adversely affect the value of an investment in our common stock.

As described elsewhere in this report, we are in default under our secured loan agreements. Defaults include events of default and financial covenant violations. Defaults under our secured loan agreements permit 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. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2019 and 2018.

In September 2017, Veritex notified obligors of events of default, including, but not limited to, the occurrence of the GEL Final Arbitration Award, associated material adverse effect conditions, failure by LE to replenish a $1.0 million payment reserve account, and the occurrence of events of default by obligors under our other secured loan agreements with Veritex, all of which constituted events of default under our secured loan agreements. Further, Veritex informed obligors that it would consider a final confirmation of the GEL Final Arbitration Award to be a material event of default under the loan agreements. Veritex did not accelerate or call due our secured loan agreements considering these factors. Instead, Veritex expressly reserved all its rights, privileges and remedies related to events of default.

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Risk Factors

In April 2019, obligors were notified by Veritex that the bank agreed to waive certain covenant defaults and forbear from enforcing its remedies under our secured loan agreements subject to: (i) the agreement and concurrence of the USDA and (ii) the replenishment of the payment reserve account on or before August 31, 2019. Following the GEL Settlement, the associated mutual releases became effective and GEL filed a stipulation of dismissal of claims against LE. As of the date of this report, LE had not replenished the payment reserve account and obligors were still in default under our secured loan agreements with Veritex.

At December 31, 2019, LE and LRM were in violation of the debt service coverage ratio, current ratio, and debt to net worth ratio financial covenants under our secured loan agreements with Veritex.

Any exercise by Veritex of its rights and remedies under our secured loan agreements would have a material adverse effect on our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations. In such a case, the trading price of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

We can provide no assurance that: (i) our assets or cash flow will be sufficient to fully repay borrowings under outstanding long-term debt, either upon maturity or if accelerated, (ii) LE and LRM will be able to refinance or restructure the payments on the long-term debt, and/or (iii) Veritex, as first lien holder, will provide future default waivers. Defaults under our 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.

A4. 

We will need to repay or refinance borrowings under the Amended Pilot Line of Credit.

The Amended Pilot Line of Credit is scheduled to mature in May 2020. We will need to repay, refinance, replace or otherwise extend the maturity of this line of credit. Our ability to repay, refinance, replace or extend this facility by its maturity date will be dependent on, among other things, business conditions, our financial performance and the general condition of the financial markets. If a financial disruption were to occur at the time that we are required to repay this indebtedness, we could be forced to undertake alternate financings, including a sale of additional common stock, negotiate for an extension of the maturity or sell assets and delay capital expenditures in order to generate proceeds that could be used to repay such indebtedness. We cannot provide any assurance that we will be able to consummate any such transaction on terms that are commercially reasonable, on terms acceptable to us or at all.

A5. 

Our substantial current debt, which is included in the current portion of long-term debt (in default), the current portion of long-term debt, related party (in default), and line of credit payable, could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

As of December 31, 2019 and 2018, we had current debt of $51.3 million and $41.9 million, respectively, consisting of bank debt, related party debt, and a line of credit payable. Blue Dolphin, as parent company, has guaranteed the indebtedness of certain subsidiaries. In addition, Affiliates have guaranteed the indebtedness of Blue Dolphin and certain of its subsidiaries. This level of debt in current liabilities and the cross guarantee agreements could have important consequences, such as: (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements 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 filing date of this report, we were current with the monthly payments required under our bank debt and line of credit payable. Our ability to service our debt is dependent upon, among other things, business conditions, our financial and operating performance, our ability to raise capital, and regulatory and other factors, many of which are beyond our control. If our working capital is not sufficient to service our debt, and any future indebtedness that we incur, our business, financial condition, and results of operations will be materially adversely affected.

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Risk Factors

A6. 

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

Adverse changes to the availability, terms 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. As a result, we cannot provide any assurance that any financing will be available to us in the future on acceptable terms or at all. Any such financing could be dilutive to our existing stockholders. If we cannot raise required funds on acceptable terms, we may further reduce our expenses and we may not be able to, among other things, (i) maintain our general and administrative expenses at current levels; (ii) successfully implement our business strategy; (iii) fund certain obligations as they become due; (iv) respond to competitive pressures or unanticipated capital requirements; or (v) repay our indebtedness. Based on the historical negative cash flows and the continued limited cash inflows in the period subsequent to year end there is substantial doubt about our ability to continue as a going concern.

A7. 

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

Affiliates control approximately 82% of the voting power of our Common Stock and, by virtue of such stock ownership, can control or exert substantial influence over us, including:

● 

Election and appointment of directors;

● 

Business strategy and policies;

● 

Mergers and other business combinations;

● 

Acquisition or disposition of assets;

● 

Future issuances of Common Stock or other securities; and

● 

Incurrence of debt or obtaining other sources of financing.

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

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

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

A8. 

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

Oil and gas operations are inherently subject to significant hazards and risks. 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 result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions and more extensive governmental regulation. These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations. These risks could harm our reputation and business, result in claims against us, and have a material adverse effect on our results of operations and financial condition.

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Risk Factors

A9. 

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

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

A10. 

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

The refining industry is highly competitive.  Our refining operations compete with domestic refiners and marketers in PADD 3 (Gulf Coast), domestic refiners in other PADD regions, and foreign refiners that import products into the U.S. Certain of our competitors have larger, more complex refineries and may be able to realize higher margins per barrel of product produced. Several of our principal competitors are integrated national or international oil companies that are larger and have 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.

A11. 

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

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

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.

A12. 

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

We are subject to the requirements of OSHA, SEMS, and comparable state statutes that regulate the protection, health, and safety of workers, and the proper design, operation and maintenance of our equipment. In addition, OSHA and certain other environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to personnel and state and local governmental authorities. 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.

16

Risk Factors

A13. 

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

Our insurance program may not cover all operational risks and costs and may not provide sufficient coverage in the event of a claim. We do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition, and results of operations.

Changes in the insurance markets subsequent to certain hurricanes and natural disasters have made it more difficult and more expensive to obtain certain types of coverage. The occurrence of an event that is not fully covered by insurance, or failure by one or more of our insurers to honor its coverage commitments for an insured event, could have a material adverse effect on our business, financial condition, and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. There is no assurance that our insurers will renew their insurance coverage on acceptable terms, if at all, or that we will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition and results of operations.

A14. 

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

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

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

At December 31, 2019 and 2018, 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, 2019 and 2018.

A15. 

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

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

A16. 

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

17

Risk Factors

A17. 

Our business could be negatively affected by security threats.

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

A18. 

We face various risks associated with increase activism against oil and natural gas exploration and development activities.

Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development.

A19. 

The outbreak of COVID-19, or an outbreak of another highly infectious or contagious disease, could adversely affect the combined company’s business, financial condition, and results of operations.

Our business will be dependent upon the willingness and ability of our customers to conduct transactions. The spread of a highly infectious or contagious disease, such as COVID-19, could cause severe disruptions in the worldwide economy, which could in turn disrupt our business, activities, and operations, as well as that of our customers. Moreover, since the beginning of January 2020, the COVID-19 outbreak has caused significant disruption in the financial markets both globally and in the United States. The spread of COVID-19, or an outbreak of another highly infectious or contagious disease, may result in a significant decrease in business and/or cause customers to be unable to meet existing payment or other obligations. A spread of COVID-19, or an outbreak of another contagious disease, could also negatively impact the availability of key personnel necessary to conduct our business. Such a spread or outbreak could also negatively impact the business and operations of third-party providers who perform critical services for our business. If COVID-19, or another highly infectious or contagious disease, spreads or the response to contain COVID-19 is unsuccessful, we could experience a material adverse effect on our business, financial condition, and results of operations.

B. 

Risks Related to Our Operations

B1. 

Refining margins are volatile, and a reduction in refining margins will adversely affect the amount of cash we will have available for working capital.

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our refined 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 products depend upon numerous factors beyond our control. The prices at which we sell refined 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 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.

18

Risk Factors

B2. 

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

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 products) at which we can sell refined 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 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 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 products, typically there is a time lag between the comparable increase or decrease in prices for refined 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 product prices adjust to reflect these changes.

Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, and refined 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 products and the volume of crude oil, feedstocks, and refined 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.

B3. 

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

Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. We have a long-term crude supply agreement in place with Pilot. Under the initial term of the crude supply agreement, Pilot will sell us approximately 24.8 million net bbls of crude oil. Thereafter, the crude supply agreement will continue on a one-year evergreen basis. Pilot may terminate the crude supply agreement at any time by providing us 60 days prior written notice. We may terminate the agreement upon the expiration of the initial term or at any time during a renewal term by giving Pilot 60 days prior written notice.

Pilot also stores crude oil at the Nixon facility under a terminal services agreement. Under the terminal services agreement, Pilot stores crude oil at the Nixon facility at a specified rate per bbl of the storage tank’s shell capacity. The terminal services agreement has an initial term that expires April 30, 2020. Thereafter, the terminal services agreement will continue on a one-year evergreen basis. Either party may terminate the terminal services agreement by providing the other party 60 days prior written notice. However, the terminal services agreement will automatically terminate upon expiration or termination of the crude supply agreement.

Our financial health could be adversely affected by defaults under our secured loan agreements, historic net losses, and working capital deficits, which could impact our ability to acquire crude oil and condensate. A failure to acquire crude oil and condensate when needed will have a material effect on our business results and operations.

B4. 

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

The Nixon refinery periodically experiences planned and unplanned temporary shutdowns. Unplanned shutdowns can occur for a variety of reasons, including voluntary regulatory compliance measures, cessation or suspension by regulatory authorities, or disabled equipment. However, in Texas the most typically reason is excessive heat or power outages from high winds and thunderstorms. Planned turnarounds are used to repair, restore, refurbish, or replace refinery equipment. Refineries typically undergo a major turnaround every three to five years. Since the Nixon refinery is still in the recommissioning phase, turnarounds are needed more frequently for unanticipated maintenance or repairs.

19

Risk Factors

We are particularly vulnerable to disruptions in our operations because all our refining operations are conducted at a single facility. Refinery downtime in 2019 totaled 21 days compared to 30 days in 2018, an improvement of 9 days. Refinery downtime in 2019 related to a maintenance turnaround (March 2019) and intermittent crude heater issues while refinery downtime in 2018 was for repair and maintenance of the naphtha stabilizer unit and two maintenance turnarounds (January and March 2018). Any scheduled or unscheduled downtime will result in lost margin opportunity, potential increased maintenance expense, and a reduction of refined products inventory, which could reduce our ability to meet our payment obligations.

B5. 

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate. Further, Affiliates may, but are not required to, fund our working capital requirements in the event our internally generated cash flows and other sources of liquidity are inadequate.

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 products and rental of petroleum storage tanks, Affiliates, and borrowings under bank facilities to meet our liquidity needs. At December 31, 2019 and 2018, accounts payable, related party totaled $0.1 million and $1.5 million, respectively. At December 31, 2019 and 2018, long-term debt and accrued interest, related party was $8.2 and $8.6 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.

B6. 

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

Our future success depends on the services of the executive officers and other key personnel and on our continuing ability to recruit, train and retain highly qualified personnel in all areas of our operations. 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.

B7. 

Loss of market share by a key customer, one of which is an Affiliate, or consolidation among our customer base could harm our operating results.

One of our significant customers is an Affiliate. The Affiliate purchases our jet fuel under a Jet Fuel Sales Agreement and bids on jet fuel contracts under preferential pricing terms due to a HUBZone certification. The Affiliate accounted for 31.3% and 28.9% of total revenue from operations in 2019 and 2018, respectively. The Affiliate represented approximately $1.4 million and $0 in accounts receivable at December 31, 2019 and 2018, respectively. The amounts will be paid under normal business terms. Amounts outstanding relating to the Jet Fuel Sales Agreement can vary significantly period to period based on the timing of the related sales and payments received. Amounts we owed to LEH under various long-term debt, related-party agreements totaled $6.2 million and $6.1 million at December 31, 2019 and 2018, respectively.

	Number Significant Customers	% Total Revenue from Operations	Portion of Accounts Receivable December 31,
2019	4	96.5%	$1.7 million
2018	4	90.3%	$0.1 million

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 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.

20

Risk Factors

B8. 

The sale of refined products to the wholesale market is our primary business, and if we fail to maintain and grow the market share of our refined products, our operating results could suffer.

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 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 products offered by our competitors.

B9. 

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

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

B10. 

We will continue to pursue acquisitions in the future.

Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition, or, if the acquisition occurs, effectively integrate the acquired business into our existing businesses. Negotiations of potential acquisitions and the integration of acquired business operations may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on reasonable terms, any new businesses may not generate the anticipated level of revenues, the anticipated cost efficiencies, or synergies may not be realized, and these businesses may not be integrated successfully or operated profitably. Our inability to successfully identify, execute, or effectively integrate future acquisitions may negatively affect our results of operations.

B11. 

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

Our suppliers source a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale. Consequently, we may be disproportionately exposed to the impact of delays or interruptions of supply from that region caused by transportation capacity constraints, curtailment of production, unavailability of equipment, facilities, personnel or services, significant governmental regulation, 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.

B12. 

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

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

B13. 

Climate change and related legislation or regulation reducing emissions of greenhouse gases could require us to incur significant costs or could result in a decrease in demand for our refined products, which could adversely affect our business.

Currently, various legislative and regulatory measures to address reporting or reduction of greenhouse gas emissions have been adopted or are in various phases of discussion or implementation. Requiring reductions in greenhouse gas emissions could cause us to incur substantial costs to: (i) operate and maintain the Nixon facility, (ii) install new emission controls at the Nixon facility, and (iii) administer and manage any greenhouse gas emissions programs, including the acquisition or maintenance of emission credits or allowances. These requirements may also adversely affect our suppliers and customers, leading to an indirect adverse effect on our business, financial condition and results of our operations.

21

Risk Factors

Requiring a reduction in greenhouse gas emissions and the increased use of renewable fuels could decrease demand for refined products, which could have an indirect, but material, adverse effect on our business, financial condition and results of operations. For example, the EPA has promulgated rules establishing greenhouse gas emission standards for new-model passenger cars, light-duty trucks and medium duty passenger vehicles. Concerns over climate change and related greenhouse gas emissions could affect demand for petroleum products as well as new energy technologies including electric vehicles, fuel cells and battery storage systems and transportation alternatives. Any of these developments, or new taxes or fees imposed on crude oil, natural gas or refined products to fund clean energy initiatives at the state or federal level, could have an indirect adverse effect on our business due to reduced demand for refined products.

Scientific studies have indicated that increasing concentrations of greenhouse gases in the atmosphere can produce changes in climate with significant physical effects, including increased frequency and severity of storms, floods and other extreme weather events that could affect our operations. Increased concern over the effects of climate change may also affect our customers’ energy strategies, consumer consumption patterns, and government and private sector alternative energy initiatives, any of which could adversely affect demand for petroleum products and have a material adverse effect on our business, financial condition and results of operations.

C. 

Risks Related to Pipeline and Facilities Assets, as well as our Pipelines and Oil and Gas Properties

C1. 

Assessment of civil penalties by BOEM for failure to satisfy orders to increase supplemental pipeline bonds and by BSEE for failure to decommission platform and pipeline assets within the time period prescribed could significantly impact our operations, liquidity, and financial condition.

We have pipelines and facilities assets that are subject to BSEE’s idle iron regulations. BSEE mandates lessees and rights-of-way holders to permanently abandon and/or remove platforms and other structures when they are no longer useful for operations. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the minimum bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM.

BDPL has historically maintained $0.9 million in financial assurance to BOEM for the decommissioning of its trunk pipeline offshore in federal waters. Following an agency restructuring of the financial assurance program, in March 2018 BOEM ordered BDPL to provide supplemental pipeline bonds totaling $4.8 million for five (5) existing pipeline rights-of-way within sixty (60) calendar days. In June 2018, BOEM issued BDPL INCs for each right-of-way that failed to comply. BDPL appealed the INCs to the IBLA, and the IBLA granted multiple extension requests that extended BDPL’s deadline for filing a statement of reasons for the appeal with the IBLA. In December 2018, BSEE issued an INC to BDPL for failure to flush and fill Pipeline Segment No. 13101.

On August 9, 2019, BDPL timely filed its statement of reasons for the appeal with the IBLA. Management met with the BOEM and BSEE on August 15, 2019. BSEE proposed that Blue Dolphin submit permit applications for decommissioning and removal of its offshore assets within six (6) months (no later than February 15, 2020), and develop and implement a safe boarding plan for submission with such permit applications. BDPL timely submitted permit applications for decommissioning and removal of the subject offshore assets on February 11, 2020. Further, BSEE proposed that Blue Dolphin conduct approved, permitted work in a safe manner within 12 months (no later than August 15, 2020). Considering BDPL’s August 2019 meeting with BOEM and BSEE, BDPL requested a stay in the IBLA matter until August 2020. The Office of the Solicitor of the U.S. Department of the Interior was agreeable to a 10-day extension while it conferred with BOEM on BDPL’s stay request. In late October 2019, BDPL filed a motion to request the 10-day extension, which motion was subsequently granted by the IBLA. The solicitor’s office consented to an additional 14-day extension for BDPL to file its reply, and BDPL filed a motion to request the 14-day extension in November 2019. The solicitor’s office indicated that BOEM would not consent to further extensions. However, the solicitor’s office signaled that BDPL’s adherence to the milestones identified in the August 15, 2019 meeting may help in future discussions with BOEM related to the INCs.

BDPL reasonably expects that successful completion of its decommissioning obligations prior to BSEE’s August 2020 deadline will significantly reduce or eliminate the amount of financial assurance required by BOEM, which may serve to partially or fully resolve the INCs. BDPL expects to complete approved, permitted decommission work by the BSEE August 2020 deadline. If decommissioning of the assets is not completed by the allowable deadline, BDPL will be subject to vigorous regulatory oversight and enforcement, including but not limited to failure to correct an INC, civil penalties, and revocation of BDPL’s operator designation, which may have a material adverse effect on our earnings, cash flows and liquidity.

22

Risk Factors

BDPL’s pending appeal of the INCs does not relieve BDPL of its obligations to provide additional financial assurance or of BOEM’s authority to impose financial penalties. If BDPL is required by BOEM to provide significant additional 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. We are currently unable to predict the outcome of the INCs. Accordingly, we have not recorded a liability on our consolidated balance sheet as of December 31, 2019.

At December 31, 2019 and 2018, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to BOEM. As of December 31, 2019, we maintained $2.6 million in AROs related to abandonment of these assets.

D. 

Risks Related to Our Common Stock

D1. 

Our stock price may decline due to sales of shares by Affiliates.

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

D2. 

We are authorized to issue up to a total of 20 million shares of our Common Stock and 2.5 million shares of preferred stock, potentially diluting equity ownership of current holders and the share price of our Common Stock.

We believe that it is necessary to maintain a sufficient number of available authorized shares of our Common Stock and Preferred Stock to provide us with the flexibility to issue Common Stock or Preferred Stock for business purposes that may arise as deemed advisable by our Board. These purposes could include, among other things, (i) future stock dividends or stock splits, which may increase the liquidity of our shares; (ii) the sale of stock to obtain additional capital or to acquire other companies or businesses, which could enhance our growth strategy or allow us to reduce debt if needed; and (iii) for other bona fide purposes. Our Board may authorize us to issue the available authorized shares of Common Stock or Preferred Stock without notice to, or further action by, our stockholders, unless stockholder approval is required by law or the rules of the OTCQX. The issuance of additional shares of Common Stock or Preferred Stock may significantly dilute the equity ownership of the current holders of our Common Stock.

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23

Properties and Legal Proceedings

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

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

See “Item 1.,” “Note (4),” “Note (10),” “Note (12),” “Note (13),” and “Note (16)” to our consolidated financial statements for additional disclosures related to our properties, leases, decommissioning obligations, and assets pledged as collateral.

ITEM 3.  LEGAL PROCEEDINGS

Resolved - GEL Settlement

As previously disclosed, GEL was awarded the GEL Final Arbitration Award in the aggregate amount of $31.3 million. In July 2018, the Lazarus Parties and GEL entered into the GEL Settlement Agreement. The GEL Settlement Agreement was subsequently amended five (5) times to extend the GEL Settlement Payment Date and/or modify certain terms related to the GEL Interim Payments or the GEL Settlement Payment. During the period September 2017 to August 2019, GEL received the following amounts from the Lazarus Parties to reduce the outstanding balance of the GEL Final Arbitration Award:

	(in millions)
Initial payment (September 2017)	$3.7
GEL Interim Payments (July 2018 to April 2019)	8.0
Settlement Payment (Multiple Payments May 7 to 10, 2019)	10.0
Deferred Interim Installment Payments (June 2019 to August 2019)	0.5
	$22.2

The GEL Settlement Effective Date occurred on August 23, 2019. As a result of the GEL Settlement: (i) the mutual releases became effective, (ii) GEL filed a stipulation of dismissal of claims against LE, and (iii) Blue Dolphin recognized a $9.1 million gain on the extinguishment of debt on its consolidated statements of operations in the third quarter of 2019. Until the GEL Settlement occurred, the debt was reflected on Blue Dolphin’s consolidated balance sheets as accrued arbitration award payable. At December 31, 2019 and 2018, accrued arbitration award payable was $0 and $21.1million, respectively.

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 exercises its rights and remedies due to defaults under our secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

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24

Market for Equity, Stockholder Matters and Purchases of Equity Securities

PART II

ITEM 5.  

MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

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

	High Bid	Low Bid		High Bid	Low Bid
2019			2018
December 31	$1.16	$0.42	December 31	$1.13	$0.40
September 30	$1.24	$0.95	September 30	$1.11	$0.22
June 30	$1.07	$0.85	June 30	$0.59	$0.11
March 31	$1.25	$0.64	March 31	$1.63	$0.53

At December 31, 2019, we had 12,327,365 shares of Common Stock outstanding. Affiliates control approximately 82% of the voting power of our Common Stock. See “Item 1A.” for risks associated with investments in our common stock.

Stockholders

At March 30, 2020, we had 271 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.

Sales of Unregistered Securities

Set forth below is information regarding the sale or issuance of shares of Common Stock by us for the years ended December 31, 2019 and 2018 that were not registered under the Securities Act of 1933:

● 

On November 14, 2019, we issued an aggregate of 1,351,851 restricted shares of Common Stock to Jonathan Carroll pursuant to guaranty fee agreements. The issuance represents payment of the common stock component of the guaranty fees for the period May 2017 through October 2019, which payments were not permissible under the GEL Settlement Agreement. We recorded an expense of approximately $0.5 million related to the share issuance. Mr. Carroll will receive payment of the common stock component of the guaranty fees on a quarterly basis going forward. The cash portion of guaranty fees owed to Jonathan Carroll will continue to be accrued and added to the principal balance of the March Carroll Note.

● 

On October 18, 2018, we issued an aggregate of 50,001 restricted shares of Common Stock to certain of our non-employee, independent directors for services rendered to the Board for the period January 1, 2018 to March 31, 2018. At March 31, 2018, the grant date market value cost basis was $0.60 per share.

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

ITEM 6.  SELECTED FINANCIAL DATA

Not applicable.

25

Management’s Discussion and Analysis

ITEM 7.  

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis is our analysis of our financial performance, financial condition, and significant trends that may affect future performance. All statements in this section, other than statements of historical fact, are forward-looking statements that are inherently uncertain. See “Important Information Regarding Forward-Looking Statements” and “Risk Factors” for a discussion of the factors that could cause actual results to differ materially from those projected in these statements. The following information concerning our business strategy, results of operations, and financial condition should be read in conjunction with “Item 1.,” “Item 1A.,” and “Item 8”.

Overview

Blue Dolphin is an independent downstream energy company operating in the Gulf Coast region of the United States. Our subsidiaries operate a light sweet-crude, 15,000-bpd crude distillation tower with approximately 1.2 million bbls of petroleum storage tank capacity in Nixon, Texas. Our assets are primarily organized in two segments: refinery operations (owned by LE) and tolling and terminaling services (owned by LRM and NPS). Active subsidiaries that are reflected in corporate and other include BDPL (inactive pipeline assets), BDPC (inactive leasehold interests in oil and gas wells), and BDSC (administrative services).

Affiliates control approximately 82% of the voting power of our Common Stock. An Affiliate operates and manages all Blue Dolphin properties and funds working capital requirements during periods of working capital deficits, and an Affiliate is a significant customer of our refined products. Blue Dolphin and certain of its subsidiaries are currently parties to a variety of agreements with Affiliates.

Business Strategy

Our primary business objective is to improve our financial profile. We intend to accomplish this objective by executing the following strategies, modified as necessary, to reflect changing economic conditions and other circumstances:

Optimizing Existing Asset Base	● Operating safely and enhancing health, safety and environmental systems. ● Planning and managing turnarounds and downtime.
Improving Operational Efficiencies	● Reducing or streamlining variable costs incurred in production. ● Increasing throughput capacity and optimizing product slate. ● Increasing tolling and terminaling revenue.
Seizing Market Opportunities	● Taking advantage of market opportunities as they arise.

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

There can be no assurance that our business strategy will be successful, that Affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing or meet financial assurance (bonding) requirements on commercially reasonable terms or at all. If Veritex exercises its rights and remedies under our secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

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.Management has determined that conditions exist that raise substantial doubt about our ability to continue as a going concern due to defaults under our secured loan agreements, historic net losses, and working capital deficits. 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 on sustained positive operating margins and working capital to sustain operations, including the purchase of crude oil and condensate and payments on long-term debt. If we are unable to achieve these goals, our business would be jeopardized, and we may not be able to continue.

26

Management’s Discussion and Analysis

2019 Successes

Despite a going concern due to defaults under our secured loan agreements, historic net losses, and working capital deficits, management took decisive steps in 2019 to further improve our operations and financial stability. Achieved milestones include:

May 2019	● Long-term crude supply contract with Pilot. ● $12.8 million line of credit agreement with Pilot. ● Terminal services agreement with Pilot.
August 2019	● GEL Settlement. ● $9.1 million gain on GEL liability extinguishment.
September 2019	● Increase of line of credit agreement with Pilot (to $13.0 million). ● Third quarter 2019 gross profit of $2.4 million.
December 2019	● Full year 2019 gross profit of $11.4 million.

Results of Operations

A discussion and analysis of the factors contributing to our consolidated financial results of operations is presented below. The financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but they should not serve as the only criteria for predicting future performance.

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

Segment Contribution Margin and Refining Gross Profit per Bbl

Segment contribution margin is used to evaluate both refinery operations and tolling and terminaling while refining gross profit per bbl is a refinery operations benchmark. Both measures supplement our financial information presented in accordance with U.S. GAAP. Management uses these non-GAAP measures to analyze our results of operations, assess internal performance against budgeted and forecasted amounts, and evaluate future impacts to our financial performance as a result of capital investments. Non-GAAP measures have important limitations as analytical tools. These non-GAAP measures, which are defined in our glossary of terms, should not be considered a substitute for GAAP financial measures. We believe these measures may help investors, analysts, lenders, and ratings agencies analyze our results of operations and liquidity in conjunction with our U.S. GAAP results. See “Non-GAAP Reconciliations” within this “Item 7.” and the financial statements within “Item 8.” for a reconciliation of Non-GAAP measures to U.S. GAAP.

Tank Rental Revenue

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

Operation Costs and Expenses

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

Refinery Throughput and Production Data

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

Refinery Downtime

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

27

Management’s Discussion and Analysis

Consolidated Results.

Year Ended December 31, 2019 (“2019”) Versus December 31, 2018 (“2018”)

Overview.Net income for 2019 increased by $7.9 million, or $0.71 per share, to $7.4 million from a net loss of $0.5 million for 2018. The significant increase mostly related to a gain on the extinguishment of debt related to the GEL Settlement; provided, however, an increase in tolling and terminaling revenue of $0.6 million, or nearly 17%, also contributed to the rise. Excluding this gain, we would have reported a net loss of $1.8 million, or a loss of $0.16 per share, for 2019.

Total Revenue from Operations.Total revenue from operations for 2019 decreased $31.5 million, or approximately 9%, to $309.3 million compared to $340.8 million for 2018. The decrease in refinery operations revenue was due to lower commodity pricing per bbl on refined products sold in 2019 compared to 2018. Tolling and terminaling revenue increased approximately $0.6 million, or nearly 17%, as a result of increased storage fees under new and renewed customer agreements.

Total Cost of Goods Sold.Total cost of goods sold was $297.8 million for 2019 compared to $331.9 million for 2018. The $34.1 million, or 10%, decrease related to lower commodity prices per bbl for crude oil and chemicals.

Gross Profit.Gross profit for 2019 totaled $11.4 million compared to gross profit of $8.8 million for 2018. The increase in gross profit primarily related to improved margins per bbl, slightly increased sales volume, and increased tank rental revenue in 2019.

General and Administrative Expenses.General and administrative expenses totaled $2.7 million in 2019 compared to $3.3 million in 2018. The $0.6 million, or nearly 19%, decrease primarily related to lower legal fees as a result of the GEL Settlement.

Depletion, Depreciation and Amortization.We recorded depletion, depreciation and amortization expenses of $2.5 million in 2019 compared to $1.9 million in 2018, an increase of $0.6 million or nearly 19%. The increase related to placing a new boiler and petroleum storage tanks into service.

Total Other Income (Expense).Total other income totaled $1.9 million in 2019 compared to an expense of $3.3 million in 2018. Other income in 2019 included a $9.1 million gain on the extinguishment of debt, which was offset by $6.8 million in interest expense associated with our secured loan agreements with Veritex, related-party debt, and the line of credit with Pilot, and a $0.5 million loss on the issuance of debt to extinguish related-party debt. Interest expense increased in 2019 as a result of completion of certain CIP for which interest was no longer being capitalized and the addition of the line of credit with Pilot.

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28

Management’s Discussion and Analysis

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

	Year Ended December 31,
	2019	2018
	(in thousands)
Refined product sales	$304,924	$337,038
Less: Total cost of goods sold	(297,827)	(331,936)
Gross profit	7,097	5,102
Sales (Bbls)	4,547	4,493
Gross Profit per Bbl	$1.56	$1.14

	Year Ended December 31,
	2019	2018
	(in thousands)
Net revenue (2)	$304,924	$337,038
Intercompany fees and sales	(2,615)	(3,270)
Operation costs and expenses	(297,113)	(331,220)
Segment Contribution Margin	$5,196	$2,548

	Year Ended December 31,
	2019	2018
Calendar	365	365
Operating	(344)	(335)
Refinery Downtime (Days)	21	30
Refinery Throughput
bpd	13,417	13,748
bbls	4,615,458	4,605,705
Capacity utilization rate	89.4%	91.7%
Refinery Production
bpd	13,096	13,372
bbls	4,504,857	4,479,701
Capacity utilization rate	87.3%	89.1%
Total refinery production (bbls)	4,504,857	4,479,701
Operating days:
bpd	13,096	13,372
Capacity utilization rate	87.3%	89.1%
(1)  See “How We Evaluate Our Operations” and “Non-GAAP Reconciliations” within “Item 7.” for further information regarding this non-GAAP measure. (2)  Net revenue excludes intercompany crude sales.

2019 Versus 2018

● 

Refining gross profit per bbl was $1.56 for 2019 compared to $1.14 in 2018, representing an increase of $0.42 per bbl. The significant increase related to higher margins as a result of market fluctuations in 2019 compared to 2018.

● 

Segment contribution margin increased approximately $2.7 million to $5.2 million in 2019 compared to $2.5 million in 2018. The increase related to improved margins per bbl and slightly increased sales volume.

● 

Refinery downtime in 2019 improved by 9 days compared to 2018; refinery downtime in 2019 related to a maintenance turnaround (March 2019) and intermittent crude heater issues while refinery downtime in 2018 was for repair and maintenance of the naphtha stabilizer unit and two maintenance turnarounds (January and March 2018).

● 

Although total refinery throughput bbls increased in 2019 versus 2018, refinery throughput on a bpd basis decreased as a result of intermittent crude heater issues.

29

Management’s Discussion and Analysis

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

	Year Ended December 31,
	2019	2018
	(in thousands)
Net revenue (2)	$4,338	$3,723
Intercompany fees and sales	2,615	3,270
Operation costs and expenses	(1,325)	(1,332)
Segment contribution margin	$5,628	$5,661

(1) 

See “How We Evaluate Our Operations” and “Non-GAAP Reconciliations” within “Item 7.” for further information regarding this non-GAAP measure.

(2) 

Net revenue excludes intercompany crude sales.

2019 Versus 2018

● 

Tolling and terminaling net revenue increased approximately $0.6 million, or nearly 17%, primarily as a result of increased storage fees under new and renewed customer agreements.

● 

Intercompany fees and sales, which reflects fees associated with an intercompany tolling agreement tied to naphtha volumes, decreased $0.7 million in 2019 compared to 2018.

●

Segment contribution margin decreased slightly in 2019 compared to 2018. Increased net revenue was offset by decreased intercompany tolling fees.

Non-GAAP Reconciliations.

Reconciliation of Segment Contribution Margin

	Year Ended December 31,
	2019	2018	2019	2018	2019	2018
	Refinery Operations		Tolling and Terminaling		Corporate and Other
	(in thousands)
Segment contribution margin	$5,196	$2,548	$5,628	$5,661	$(222)	$(444)
General and administrative expenses, including LEH operating fee	(1,252)	(1,232)	(262)	(245)	(1,145)	(1,795)
Depreciation and amortization	(1,913)	(1,842)	(396)	(91)	(181)	-
Interest and other non-operating income (expenses), net	5,668	(2,229)	(2,398)	(285)	(1,362)	(829)
Income (loss) before income taxes	7,699	(2,755)	2,572	5,040	(2,910)	(3,068)
Income tax benefit	-	-	-	-	-	0
Income (loss) before income taxes	$7,699	$(2,755)	$2,572	$5,040	$(2,910)	$(3,068)

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30

Management’s Discussion and Analysis

Capital Resources and Liquidity

Our primary cash requirements relate to: (i) purchasing crude oil and condensate for the operation of the Nixon refinery, (ii) paying our direct operating expenses under the Amended and Restated Operating Agreement, (iii) servicing long-term debt, and (iv) completing construction in progress. In instances where we experience a working capital deficit, we have historically relied on Affiliates to meet our liquidity needs. While we believe that we can fund our operations through revenue from operations and Affiliate financing, we may not be able to, among other things, (i) maintain our current general and administrative spending levels; (ii) fund certain obligations as they become due; and (iii) respond to competitive pressures or unanticipated capital requirements. We cannot provide any assurance that financing will be available to us in the future on acceptable terms.

We had a working capital deficit of $59.4 million and $71.9 million at December 31, 2019 and 2018, respectively. Excluding the current portion of long-term debt, we had a working capital deficit of $19.6 million and $30.0 at December 31, 2019 and 2018, respectively. See “Item 1A.” for risks factors related to liquidity and working capital.

Debt Overview.

Total Debt

	December 31,
	2019	2018
	(in thousands)
USDA-Guaranteed Loans
First Term Loan Due 2034 (in default)	$21,776	$22,593
Second Term Loan Due 2034 (in default)	9,031	9,353
Amended Pilot Line of Credit	11,786	-
Notre Dame Debt (in default)	8,617	7,821
Related-Party Debt
BDPL Loan Agreement (in default)	6,174	5,534
March Ingleside Note (in default)	1,004	1,283
March Carroll Note (in default)	997	1,147
June LEH Note (in default)	-	611
Capital Leases	-	41
Total Debt	59,385	48,383
Less: Current portion of long-term debt, net	(51,301)	(41,904)
Less: Unamortized debt issue costs	(2,096)	(2,006)
Less: Accrued interest payable (in default)	(5,988)	(4,473)
	$-	$-

Principal payments on long-term debt totaled $2.2 million in 2019 compared to $0.9 million in 2018. As of the filing date of this report, we were current on required monthly payments under our secured loan agreements with Veritex. No payments have been made under subordinated loan agreements.

On November 14, 2019, Mr. Carroll was issued an aggregate of 1,351,851 restricted shares of Common Stock, which represents payment of the common stock component of the guaranty fees for the period May 2017 through October 2019. We recorded an expense of approximately $0.5 million related to the share issuance. As previously disclosed, payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements were prohibited pursuant to the GEL Settlement Agreement. Following the GEL Settlement, management resumed payments of the common stock component to Mr. Carroll under the agreements.

Mr. Carroll will receive payment of the common stock component of the guaranty fees on a quarterly basis going forward. Currently, management does not intend on paying Mr. Carroll the cash portion due to Blue Dolphin’s working capital deficits in the foreseeable future. The cash portion of guaranty fees owed to Mr. Carroll will continue to be accrued and added to the principal balance of the March Carroll Note. See “Note (3)” to our consolidated financial statements for additional disclosures related to Affiliates and working capital deficits.

Debt Defaults. Except for the Amended Pilot Line of Credit, all of our debt is in default. Defaults under our secured loan agreements with Veritex include events of default and financial covenant violations. In addition, certain of our related-party debt is in default. Defaults under our secured loan agreements permit 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. See “Note (3)” and “Note (10)” to our consolidated financial statements for additional disclosures related to defaults in our debt obligations.

31

Management’s Discussion and Analysis

Contractual Obligations.

Related-Party

Agreement/Transaction	Parties	Type	Effective Date	Interest Rate	Key Terms
Amended and Restated Guaranty Fee Agreement	Jonathan Carroll - LE	Debt	04/01/2017	2.00%	Tied to payoff of LE $25 million Veritex loan; payments 50% cash, 50% Common Stock
Amended and Restated Guaranty Fee Agreement	Jonathan Carroll - LRM	Debt	04/01/2017	2.00%	Tied to payoff of LRM $10 million Veritex loan; payments 50% cash, 50% Common Stock
March Carroll Note (in default)	Jonathan Carroll – Blue Dolphin	Debt	03/31/2017	8.00%	Blue Dolphin working capital; matured 01/01/2019; interest still accruing
March Ingleside Note (in default)	Ingleside – Blue Dolphin	Debt	03/31/2017	8.00%	Blue Dolphin working capital; reflects amounts owed to Ingleside under previous Amended and Restated Tank Lease Agreement; matured 01/01/2019; interest still accruing
June LEH Note (in default)	LEH – Blue Dolphin	Debt	03/312017	8.00%	Blue Dolphin working capital; reflects amounts owed to LEH under Amended and Restated Operating Agreement; reflects amounts owed to Jonathan Carroll under guaranty fee agreements; matured 01/01/2019; interest still accruing
Loan and Security Agreement (in default)	LEH - BDPL	Debt	08/15/2016	16.00%	2-year term; $4.0 million principal amount; $0.5 million annual payment; proceeds used for working capital; no financial maintenance covenants; secured by certain BDPL property

Third-Party Debt

Loan Description	Original Principal Amount (in millions)	Maturity Date	Monthly Principal and Interest Payment	Interest Rate	Loan Purpose
USDA-Guaranteed Loans
First Term Loan Due 2034 (in default)	$25.0	Jun 2034	$0.2 million	WSJ Prime + 2.75%	Refinance loan; capital improvements
Second Term Loan Due 2034 (in default)	$10.0	Dec 2034	$0.1 million	WSJ Prime + 2.75%	Refinance bridge loan; capital improvements
Notre Dame Debt (in default)	$11.7(1)	Jan 2018	No payments to date; payment rights subordinated(2)	16.00%	Working capital; reduce balance of GEL Final Arbitration Award
Amended Pilot Line of Credit	$13.0	May 2020	----	12.00%	GEL Settlement Payment, NPS purchase of crude oil from Pilot, and working capital

(1) 

Original principal amount was $8.0 million; pursuant to a 2017 sixth amendment, the Notre Dame Debt was amended to increase the principal amount by $3.7 million; the additional principal was used to reduce the GEL Final Arbitration Award by $3.6 million.

(2) 

Pursuant to a 2015 subordination agreement, the holder of the Notre Dame Debt agreed to subordinate their right to payments, as well as any security interest and liens on the Nixon facility’s business assets, in favor of Veritex as holder of the First Term Loan Due 2034.

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32

Management’s Discussion and Analysis

Offshore Decommissioning

We have pipelines and facilities assets that are subject to BSEE’s idle iron regulations. BSEE mandates lessees and rights-of-way holders to permanently abandon and/or remove platforms and other structures when they are no longer useful for operations. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the minimum bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM.

In March 2018, BOEM ordered BDPL to provide supplemental pipeline bonds totaling $4.8 million related to five (5) existing pipeline rights-of-way. In June 2018, BOEM issued BDPL INCs for each right-of-way that failed to comply. BDPL appealed the INCs to the IBLA, and the IBLA granted multiple extension requests that extended BDPL’s deadline for filing a statement of reasons for the appeal with the IBLA. In December 2018, BSEE issued an INC to BDPL for failure to flush and fill Pipeline Segment No. 13101.

On August 9, 2019, BDPL timely filed its statement of reasons for the appeal with the IBLA. Management met with the BOEM and BSEE on August 15, 2019. BSEE proposed that Blue Dolphin submit permit applications for decommissioning and removal of its offshore assets within six (6) months (no later than February 15, 2020), and develop and implement a safe boarding plan for submission with such permit applications. BDPL timely submitted permit applications for decommissioning and removal of the subject offshore assets on February 11, 2020. Further, BSEE proposed that Blue Dolphin conduct approved, permitted work in a safe manner within 12 months (no later than August 15, 2020). Considering BDPL’s August 2019 meeting with BOEM and BSEE, BDPL requested a stay in the IBLA matter until August 2020. The Office of the Solicitor of the U.S. Department of the Interior was agreeable to a 10-day extension while it conferred with BOEM on BDPL’s stay request. In late October 2019, BDPL filed a motion to request the 10-day extension, which motion was subsequently granted by the IBLA. The solicitor’s office consented to an additional 14-day extension for BDPL to file its reply, and BDPL filed a motion to request the 14-day extension in November 2019. The solicitor’s office indicated that BOEM would not consent to further extensions. However, the solicitor’s office signaled that BDPL’s adherence to the milestones identified in the August 15, 2019 meeting may help in future discussions with BOEM related to the INCs.

BDPL reasonably expects that successful completion of its decommissioning obligations prior to BSEE’s August 2020 deadline will significantly reduce or eliminate the amount of financial assurance required by BOEM, which may serve to partially or fully resolve the INCs. BDPL expects to complete approved, permitted decommission work by the BSEE August 2020 deadline. If decommissioning of the assets is not completed by the allowable deadline, BDPL will be subject to vigorous regulatory oversight and enforcement, including but not limited to failure to correct an INC, civil penalties, and revocation of BDPL’s operator designation, which may have a material adverse effect on our earnings, cash flows and liquidity.

BDPL’s pending appeal of the INCs does not relieve BDPL of its obligations to provide additional financial assurance or of BOEM’s authority to impose financial penalties. If BDPL is required by BOEM to provide significant additional 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. We are currently unable to predict the outcome of the INCs. Accordingly, we have not recorded a liability on our consolidated balance sheet as of December 31, 2019.

At December 31, 2019 and 2018, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to BOEM. As of December 31, 2019, we maintained $2.6 million in AROs related to abandonment of these assets.

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33

Management’s Discussion and Analysis

Sources and Use of Cash.

Components of Cash Flows

	Year Ended December 31,
	2019	2018
	(in thousands)
Cash Flows Provided By (Used In):
Operating activities	$(8,351)	$1,005
Investing activities	(1,574)	(2,029)
Financing activities	8,928	543
Increase (Decrease) in Cash and Cash Equivalents	$(997)	$(481)

2019 Versus 2018

We had a cash flow deficit from operations of $8.4 million for 2019 compared to cash flow from operations of $1.0 million for 2018. The approximate $9.4 million decrease in cash flow from operations primarily related to payments to GEL under the GEL Settlement Agreement in 2019.

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.

Capital Improvement Expansion Project

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. However, smaller efficiency improvements have been made as well. In the short-term, increased petroleum storage capacity has helped with de-bottlenecking the refinery. In the long-term, additional petroleum storage capacity will allow for increased refinery throughput of up to approximately 30,000 bpd. Increased petroleum storage capacity for tolling and terminaling operations provides an opportunity to generate additional tolling and terminaling revenue.

2019 Capital Expenditures

During 2019, capital expenditures totaled $1.6 million compared to $2.0 million during 2018. Expenses included work on a petroleum storage tank, engineering work in preparation for a planned turnaround, and upgrades to the crude heaters, which, when complete will alleviate bottlenecks and improve capacity.

Future Expected Capital Expenditures

For the next 12 to 18 months, we expect to continue to incur capital expenditures related to facility and land improvements, installation of new and/or refurbished refinery process equipment, and completion of an unfinished petroleum storage tank. Capital spending is being funded by cash flow from operations, Affiliates, and available funding under a loan from Veritex that was secured in 2015. Unused amounts under the Veritex loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets. See “Note (10)” to our consolidated financial statements for additional disclosures related to borrowings for capital spending.

Off-Balance Sheet Arrangements.None.

34

Management’s Discussion and Analysis

Accounting Standards.

Critical Accounting Policies and Estimates

Our significant accounting policies, recent accounting developments are described in “Note (2)” to our consolidated financial statements. We prepare our financial statements in conformity with U.S. GAAP, which requires us to make estimates and assumptions about future events that affect the amounts reported in the financial statements and accompanying footnotes. Actual results could differ from those estimates. We believe that the policies and estimates related to long-lived assets, revenue recognition, inventory, AROs, and income taxes are most important to the portrayal of our financial condition and results of operations and require management’s most difficult, subjective and complex judgments:

New Accounting Standards and Disclosures

New accounting standards and disclosures are discussed in “Note (2)” to our consolidated financial statements.

Remainder of Page Intentionally Left Blank

35

Quantitative and Qualitative Disclosure

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

Remainder of Page Intentionally Left Blank

36

Financial Statements

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of Blue Dolphin Energy Company

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and Subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for the years then ended, and the related notes (collectively referred to as the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

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

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

Basis for Opinion

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

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

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

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

/s/ UHY LLP

___________

UHY LLP

Sterling Heights, Michigan

March 30, 2020

37

Financial Statements

Consolidated Balance Sheets

	December 31,
	2019	2018
	(in thousands except share amounts)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$72	$14
Restricted cash	49	49
Accounts receivable, net	446	379
Accounts receivable, related party (Note 3)	1,364	-
Prepaid expenses and other current assets (Note 6)	2,276	1,786
Deposits	158	194
Inventory (Note 7)	1,645	1,510
Refundable federal income tax (Note 14)	65	108
Total current assets	6,075	4,040
LONG-TERM ASSETS
Total property and equipment, net (Note 8)	63,893	64,697
Operating lease ROU assets (Note 13)	649	-
Restricted cash, noncurrent	547	1,602
Surety bonds (Note 16)	230	230
Deferred tax assets, net (Note 14)	50	108
Total long-term assets	65,369	66,637
TOTAL ASSETS	71,444	70,677
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion, in default (Note 10)	33,836	34,863
Line of credit payable, less umamortized debt issue costs (Note 11)	11,464	-
Long-term debt, related party, current portion, in default (Note 3)	6,001	7,041
Interest payable (in default) (Note 10)	3,814	2,939
Interest payable, related party (in default) (Note 3)	2,174	1,534
Accounts payable	1,877	2,719
Accounts payable, related party (Note 3)	149	1,529
Current portion of lease liabilities (Note 13)	251	-
Asset retirement obligations (Note 12)	2,565	2,580
Accrued expenses and other current liabilities (Note 9)	3,333	1,571
Accrued arbitration award payable (Note 16)	-	21,128
Total current liabilities	65,464	75,904
LONG-TERM LIABILITIES
Long-term lease liabilities, net of current portion (Note 13)	564	-
Deferred revenue	1,930	-
Total long-term liabilities	2,494	-
TOTAL LIABILITIES	67,958	75,904
Commitments and contingencies (Note 16)
STOCKHOLDERS' EQUITY (DEFICIT)
Common Stock shares issued and outstanding (12,327,365 in 2019 and 10,975,514 in 2018) (1)	123	110
Additional paid-in capital	38,275	36,936
Accumulated deficit	(34,912)	(42,273)
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)	3,486	(5,227)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$71,444	$70,677

(1) 

Blue Dolphin has 20,000,000 shares of common stock, par value $0.01 per share, and 2,500,000 shares of preferred stock, par value $0.10 per share, authorized. There are no shares of preferred stock issued and outstanding.

The accompanying notes are an integral part of these consolidated financial statements.

38

Financial Statements

Consolidated Statements of Operations

	Year Ended December 31,
	2019	2018
	(in thousands except share and per-share amounts)
REVENUE FROM OPERATIONS
Refinery operations (Note 4)	$304,924	$337,038
Tolling and terminaling (Note 4)	4,338	3,723
Total revenue from operations	309,262	340,761
COST OF GOODS SOLD
Crude oil, fuel use, and chemicals	289,273	322,297
Other conversion costs	8,554	9,639
Total costs of goods sold	297,827	331,936
Gross profit	11,435	8,825
COST OF OPERATIONS
LEH operating fee (Note 3)	611	614
Other operating expenses	222	180
General and administrative expenses	2,659	3,272
Depletion, depreciation and amortization	2,490	1,933
Accretion of AROs (Note 12)	-	266
Total cost of operations	5,982	6,265
Income from operations	5,453	2,560
OTHER INCOME (EXPENSE)
Easement, interest and other income	4	20
Interest and other expense	(6,750)	(3,363)
Loss on issuance of shares to extinguish related-party debt	(474)	-
Gain on extinguishment of debt	9,128	-
Total other income (expense) (Note 3)	1,908	(3,343)
Income (loss) from operations	7,361	(783)
		-
Income tax benefit	-	260
Net income (loss)	$7,361	$(523)
Income (loss) per common share (Note 15):
Basic	$0.66	$(0.05)
Diluted	$0.66	$(0.05)
Weighted average number of common shares outstanding (Note 15):	11,156,995	10,935,787
Basic	11,156,995	10,935,787
Diluted

The accompanying notes are an integral part of these consolidated financial statements.

39

Financial Statements

Consolidated Statements of Stockholders’ Equity (Deficit)

	Common Stock
			Additional		Total
			Paid-In	Accumulated	Stockholders’
	Shares Issued	Par Value	Capital	Deficit	Equity (Deficit)
	(in thousands except share amounts)
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)
Common stock issued for extinguishment
of related-party debt	1,351,851	13	1,339		1,352
Net income	-	-	-	7,361	7,361
Balance at December 31, 2019	12,327,365	$123	$38,275	$(34,912)	$3,486

The accompanying notes are an integral part of these consolidated financial statements.

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40

Financial Statements

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2019	2018
	(in thousands)
OPERATING ACTIVITIES
Cash flows provided by (used in) operating activities:
Net income (loss)	$7,361	$(523)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depletion, depreciation and amortization	2,490	1,933
Deferred income tax	-	(216)
Amortization of debt issue costs	629	128
Guaranty fees paid in kind	625	-
Accretion of asset retirement obligations	-	266
Loss on issuance of shares for extinguishment of related-party debt	474	-
Common stock issued for services	-	30
Gain on extinguishment of debt	(9,128)	-
Changes in accounts receivable	(67)	978
Changes in accounts receivable, related party	(1,364)	653
Changes in prepaid expenses and other current assets	(389)	(579)
Changes in deposits and other assets	36	(65)
Changes in inventory	(135)	1,579
Changes in accrued arbitration award	(12,000)	(6,000)
Changes in accounts payable, accrued expenses and other liabilities	4,497	2,266
Changes in accounts payable, related party	(1,380)	555
Net cash from operating activities	(8,351)	1,005
INVESTING ACTIVITIES
Cash flows from (used in) investing activities:
Capital expenditures	(1,574)	(2,029)
Net cash used in investing activities	(1,574)	(2,029)
FINANCING ACTIVITIES
Cash flows from (used in) financing activities:
Proceeds from line of credit payable	12,402	-
Payments on debt	(2,241)	(890)
Payments of debt issuance costs	(322)	-
Net activity on related-party debt	(911)	1,433
Net cash from financing activities	8,928	543
Increase (Decrease) in cash and cash equivalents	(997)	(481)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	1,665	2,146
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$668	$1,665
Supplemental Information:
Non-cash investing and financing activities:
Financing of capital expenditures via capital lease	$86	$4
Financing of guaranty fees via long-term debt, related party	$625	$644
Payment of related-party debt via fixed asset exchange	$474	$-
Issuance of shares to settle related-party debt	$878	$-
Line of credit closing costs included in principal balance	$398	$-
Interest paid	$3,474	$2,823
Income taxes paid (received)	$(101)	$-

The accompanying notes are an integral part of these consolidated financial statements.

41

Notes to Consolidated Financial Statements

Notes to Consolidated Financial Statements

(1) 

Organization

Overview

Blue Dolphin is an independent downstream energy company operating in the Gulf Coast region of the United States. Our subsidiaries operate a light sweet-crude, 15,000-bpd crude distillation tower with approximately 1.2 million bbls of petroleum storage tank capacity in Nixon, Texas. Blue Dolphin was formed in 1986 as a Delaware corporation and is traded on the OTCQX under the ticker symbol “BDCO”.

Our assets are primarily organized in two segments: refinery operations (owned by LE) and tolling and terminaling services (owned by LRM and NPS). Subsidiaries that are reflected in corporate and other include BDPL (inactive pipeline and facilities assets), BDPC (inactive leasehold interests in oil and gas wells), and BDSC (administrative services). See “Note (4)” to our consolidated financial statements for more information about our business segments.

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

Affiliates

Affiliates control approximately 82% of the voting power of our Common Stock. An Affiliate operates and manages all Blue Dolphin properties and funds working capital requirements during periods of working capital deficits, and an Affiliate is a significant customer of our refined products. Blue Dolphin and certain of its subsidiaries are currently parties to a variety of agreements with Affiliates. See “Note (3)” to our consolidated financial statements for additional disclosures related to Affiliate risk factors, Affiliate agreements and arrangements, and working capital deficits.

Going Concern

Management has determined that certain factors raise substantial doubt about our ability to continue as a going concern. These factors include the following:

Defaults Under Secured Loan Agreements. LE and LRM each have loans with Veritex in the original aggregate amount of $35.0 million. These loans are guaranteed 100% by the USDA. As described in “Note (10)” to our consolidated financial statements, we are in default under our secured loan agreements. Defaults include events of default and financial covenant violations. Defaults under our secured loan agreements permit 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. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2019 and 2018.

Events of Default. In September 2017, Veritex notified obligors of events of default, including, but not limited to, the occurrence of the GEL Final Arbitration Award, associated material adverse effect conditions, failure by LE to replenish a $1.0 million payment reserve account, and the occurrence of events of default by obligors under our other secured loan agreements with Veritex, all of which constituted events of default under our secured loan agreements. Further, Veritex informed obligors that it would consider a final confirmation of the GEL Final Arbitration Award to be a material event of default under the loan agreements. Veritex did not accelerate or call due our secured loan agreements considering these factors. Instead, Veritex expressly reserved all its rights, privileges and remedies related to events of default.

In April 2019, obligors were notified by Veritex that the bank agreed to waive certain covenant defaults and forbear from enforcing its remedies under our secured loan agreements subject to: (i) the agreement and concurrence of the USDA and (ii) the replenishment of the payment reserve account on or before August 31, 2019. Following the GEL Settlement, the associated mutual releases became effective and GEL filed a stipulation of dismissal of claims against LE. As of the date of this report, LE had not replenished the payment reserve account and obligors were still in default under our other secured loan agreements with Veritex.

Financial Covenant Violations. At December 31, 2019, LE and LRM were in violation of the debt service coverage ratio, current ratio, and debt to net worth ratio financial covenants under our secured loan agreements with Veritex.

Any exercise by Veritex of its rights and remedies under our secured loan agreements would have a material adverse effect on our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations. In such a case, the trading price of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

42

Notes to Consolidated Financial Statements

We can provide no assurance that: (i) our assets or cash flow will be sufficient to fully repay borrowings under outstanding long-term debt, either upon maturity or if accelerated, (ii) LE and LRM will be able to refinance or restructure the payments on the long-term debt, and/or (iii) Veritex, as first lien holder, will provide future default waivers. Defaults under our 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. See “Note (1)” and “Note (10)” to our consolidated financial statements for additional information related to defaults under our secured loan agreements and their potential effects on our business, financial condition, and results of operations.

Net Losses and Working Capital Deficits. Net income for 2019 increased by $7.9 million, or $0.71 per share, to $7.4 million from a net loss of $0.5 million for 2018. The significant increase mostly related to a gain on the extinguishment of debt related to the GEL Settlement, provided, however, an increase in tolling and terminaling revenue of $0.6 million, or nearly 17%, also contributed to the rise. Excluding this gain, we would have reported a net loss of $1.8 million, or a loss of $0.16 per share, for 2019.

We had a working capital deficit of $59.4 million and $71.9 million at December 31, 2019 and 2018, respectively. Excluding the current portion of long-term debt, we had a working capital deficit of $19.6 million and $30.0 million at December 31, 2019 and 2018, respectively. We had cash and cash equivalents and restricted cash (current portion) of $0.07 million and $0.05 million, respectively, at December 31, 2019. Comparatively, we had cash and cash equivalents and restricted cash (current portion) of $0.01 million and $0.05 million, respectively, at December 31, 2018.

Operating Risks

Successful execution of our business strategy depends on several key factors, including, having adequate working capital to meet operational needs and regulatory requirements, maintaining safe and reliable operations at the Nixon facility, meeting contractual obligations, and having favorable margins on refined products. During the third quarter of 2019, management achieved the GEL Settlement and realized a $9.1 million gain on the extinguishment of the liability. Management believes that it is continuing to take other steps to further improve operations and financial stability. However, there can be no assurance that our business strategy will be successful, that Affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing or meet financial assurance (bonding) requirements on commercially reasonable terms or at all. If Veritex exercises its rights and remedies under our secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

The Amended Pilot Line of Credit is scheduled to mature in May 2020. We will need to repay, refinance, replace or otherwise extend the maturity of this line of credit. Our ability to repay, refinance, replace or otherwise extend this facility by its maturity date will be dependent on, among other things, business conditions, our financial performance and the general condition of the financial markets. If a financial disruption were to occur at the time that we are required to repay this indebtedness, we could be forced to undertake alternate financings, including a sale of additional common stock, negotiate for an extension of the maturity or sell assets and delay capital expenditures in order to generate proceeds that could be used to repay such indebtedness. We cannot provide any assurance that we will be able to consummate any such transaction on terms that are commercially reasonable, on terms acceptable to us or at all.

(2) 

Principles of Consolidation and Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements, which include Blue Dolphin and its subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles and the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in FASB’s ASC, the single source of GAAP. All significant intercompany items have been eliminated in consolidation. Additionally, any material subsequent events that occurred after the date through which this report covers have been properly recognized or disclosed in our financial statements. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.

In 2018, Blue Dolphin obtained 100% of the issued and outstanding membership interest of NPS, a Delaware limited liability company, from Lazarus Midstream pursuant to an Assignment Agreement. The transaction represented transfer of a vacant shell entity owned by Lazarus Midstream to Blue Dolphin for the nominal fee of $10.00. The assignment of interest facilitated settlement financing possibilities under the GEL Settlement Agreement. The assignment was accounted for as a combination of entities under common control. Accordingly, the recognized assets and liabilities of NPS were transferred at their carrying amounts at the date of transfer and the results of operations are included for 2019 and 2018. NPS did not have significant assets, liabilities or results of operations prior to the assignment. NPS holds a leasehold interest in petroleum storage tanks at the Nixon facility. NPS’ revenues and expenses are included in our Tolling and Terminaling business segment.

Significant Accounting Policies

Use of Estimates. We have made several estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with U.S. GAAP. We review our estimates on an ongoing basis using currently available information. Changes in facts and circumstances may result in revised estimates and actual results could differ from those estimates.

43

Notes to Consolidated Financial Statements

Cash and Cash Equivalents. Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Restricted Cash. Restricted cash, current portion primarily represents a payment reserve account held by Veritex as security for payments under a loan agreement. Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of construction related expenses to complete building new petroleum storage tanks.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are presented net of any necessary allowance(s) for doubtful accounts. Receivables are recorded at the invoiced amount and generally do not bear interest. An allowance for doubtful accounts is established, when necessary, based on prior experience and other factors which, in management's judgment, deserve consideration in estimating bad debts.  Management assesses collectability of the customer’s account based on current aging status, collection history, and financial condition.  Based on a review of these factors, management establishes or adjusts the allowance for specific customers and the entire accounts receivable portfolio.  We had an allowance for doubtful accounts of $0.1 million at both December 31, 2019 and 2018.

Inventory. Inventory primarily consists of refined products, crude oil and condensate, and chemicals. Inventory is valued at lower of cost or net realizable value with cost determined by the average cost method, and net realizable value determined based on estimated selling prices less associated delivery costs. If the net realizable value of our refined 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. See “Note (7)” to our consolidated financial statements for additional disclosures related to inventory.

Property and Equipment.

Refinery and Facilities. We plan to continue making improvements to the crude distillation tower based on operational needs and technological advances. Additions to refinery and facilities assets are capitalized, and expenditures for repairs and maintenance are expensed as incurred. 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. We did not record any impairment of our refinery and facilities assets for the periods presented.

Pipelines and Facilities. 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 we performed periodic impairment testing of our pipeline and facilities assets in 2016. Upon completion of that testing, our pipeline assets were fully impaired at December 31, 2016. All pipeline transportation services to third parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines. We plan to decommission the offshore pipeline assets in the third quarter of 2020.

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.

CIP. CIP expenditures, including capitalized interest, relate to construction and refurbishment activities and equipment for the Nixon Facility. These expenditures are capitalized as incurred. Depreciation begins once the asset is placed in service. See “Note (8)” to our consolidated financial statements for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and CIP.

Leases. We evaluate if a contract is or contains a lease at inception of the contract. If we determine that a contract is or contains a lease, we recognize ROU asset and lease liability at the commencement date of the lease based on the present value of lease payments over the lease term. The present value of the lease payments is determined by using the implicit rate when readily determinable. If not determinable, we use the incremental borrowing rate to discount lease payments to present value. Lease terms include options to extend or terminate the lease when it is reasonably certain that we will exercise those options.

We recognize ROU assets and lease liabilities for leasing arrangements with terms greater than one year. We account for lease and non-lease components in a contract as a single lease component for all classes of underlying assets. We allocate the consideration in these contracts based on pricing information contained in the lease.

44

Notes to Consolidated Financial Statements

Expense for an operating lease is recognized as a single lease cost on a straight-line basis over the lease term and is reflected in the appropriate income statement line item based on the leased asset’s function. Amortization expense of a finance lease ROU asset is recognized on a straight-line basis over the lesser of the useful life of the leased asset or the lease term. However, if the lease transfers ownership of the finance lease ROU asset to us at the end of the lease term, the finance lease ROU asset is amortized over the useful life of the leased asset. Amortization expense is reflected in ‘depreciation and amortization expense.’ Interest expense is incurred based on the carrying value of the lease liability and is reflected in ‘interest and other expense.’

Revenue Recognition.

Refinery Operations Revenue. Revenue from the sale of refined products is recognized when the product is sold to the customer in fulfillment of performance obligations. Each load of refined 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 product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between the 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. Tolling and terminaling revenue represents fees pursuant to: (i) 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 and (ii) 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.

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 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 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.

Deferred Revenue. We record deferred revenue when cash payments are received or due in advance of our performance. An increase in the deferred revenue balance reflects cash payments received or due in advance of satisfying our performance obligations, offset by recognized revenue that was included in the deferred revenue balance at the beginning of the period. Deferred revenue represents a liability as of the balance sheet date related to a revenue producing activity for which revenue has not yet been recognized. We record deferred revenue when we receive consideration under a contract before achieving certain criteria that must be met for revenue to be recognized in conformity with GAAP.

Income Taxes. Deferred income taxes are determined based on the differences between the financial reporting and tax basis of assets and liabilities, as well as operating losses and tax credit carryforwards using currently enacted tax rates and laws in effect for the year in which the differences are expected to reverse. We record a valuation allowance against deferred income tax assets if it is more likely than not that those assets will not be realized. The provision for income taxes comprises our current tax liability and change in deferred income tax assets and liabilities.

Significant judgment is required in evaluating uncertain tax positions and determining its provision for income taxes. As of each reporting date, we consider new evidence, both positive and negative, to determine the realizability of deferred tax assets. We consider whether it is more likely than not that a 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. When we determine that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. A significant piece of objective negative evidence evaluated was cumulative losses incurred over the three-year period ended December 31, 2018. Such objective evidence limits 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, 2019 and 2018. We expect to recover deferred tax assets related to AMT credit carryforwards. In addition, we have NOL carryforwards that remain available for future use.

45

Notes to Consolidated Financial Statements

The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At December 31, 2019 and 2018, there were no uncertain tax positions for which a reserve or liability was necessary. See “Note (14)” to our consolidated financial statements for more information related to income taxes.

Impairment or Disposal of Long-Lived Assets. We periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. The GEL Final Arbitration Award represented a significant adverse change that could affect the value of a long-lived asset, and management performed potential impairment testing of our refinery and facilities assets in 2019 and 2018. Upon completion of that testing, no impairment was deemed necessary and we did not record any impairment of our refinery and facilities assets for the periods presented.

Asset Retirement Obligations. We record a liability for the discounted fair value of an ARO in the period incurred, and we also capitalize the corresponding cost 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.

We have concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, we believe that these assets have indeterminate lives 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 facilities 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 for plugging and abandoning wells and restoring land and sea-beds. Cost estimates for each of our assets were developed based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. 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. See “Note (12)” to our consolidated financial statements for additional information related to AROs.

Computation of Earnings Per Share. We present basic and diluted EPS. Basic EPS excludes dilution and is computed by dividing net income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity. The number of shares related to restricted stock included in diluted EPS is based on the “Treasury Stock Method.” We do not have issued options, warrants, or similar instruments. See “Note (15)” to our consolidated financial statements for additional information related to EPS.

New Pronouncements Adopted.

Leases. Beginning in February 2016, FASB amended its accounting guidance for leases and subsequently updated the guidance several times [ASUs 2016-02, Leases (Topic 842), 2018-10, 2018-11, 2018-20, and 2019-01]. The guidance requires a lessee to recognize assets and liabilities on the balance sheet arising from leases with terms greater than 12 months. While lessor guidance is relatively unchanged, certain amendments were made to conform with changes made to lessee accounting and the amended revenue recognition guidance. The new guidance continues to classify leases as either finance or operating, with classification affecting the presentation and pattern of expense and income recognition, in the statement of operations. It also requires additional quantitative and qualitative disclosures about leasing arrangements. We adopted the new guidance on January 1, 2019 using the modified retrospective approach, which was applied beginning on the adoption date. Comparative information has not been restated and continues to be reported under the accounting guidance in effect for those periods. The adoption did not have a material effect on our consolidated statements of operations or cash flows. On the adoption date we recognized operating lease ROU assets, net of pre-existing deferred rent, and operating lease liabilities on our consolidated balance sheet of approximately $0.8 million and $0.9 million, respectively.

46

Notes to Consolidated Financial Statements

New Pronouncements Issued, Not Yet Effective.

Codification Updates to SEC Sections. In July 2019, FASB issued ASU 2019-07, Codification Updates to SEC Sections, which amends certain SEC sections or paragraphs within the FASB ASC. The amendments are being made pursuant to SEC Final Rule Releases No. 33-10532, Disclosure Update and Simplification, and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates (SEC Update). The SEC Final Rule Releases, which also require improvements to the XBRL taxonomy, were made to improve, update, and simplify SEC regulations on financial reporting and disclosure. For public companies, the amendments in ASU 2019-07 are effective upon issuance. We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

Consolidation. In October 2018, FASB issued ASU 2018-17,Consolidation (Topic 810). This ASU provides targeted improvements to related-party guidance for variable interest entities. 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.

Income Taxes. In March 2018, FASB issued ASU 2018-05,Income Taxes (Topic 740). This guidance amends SEC paragraphs in ASC 740, Income Taxes, to reflect Staff Accounting Bulletin No. 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.

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47

Notes to Consolidated Financial Statements

(3) 

Related-Party Transactions

Working Capital

Currently, we depend on Affiliates for financing when revenue from operations and borrowings under bank facilities are insufficient to meet our liquidity and working capital needs. Such borrowings are reflected in our consolidated balance sheets in accounts payable, related party, and/or long-term debt, related party.

Affiliate Agreements/Transactions

Blue Dolphin and certain of its subsidiaries are party to several agreements with Affiliates. Management believes that these related-party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions. Related-party transactions consist of the following:

Agreement/Transaction	Parties	Type	Effective Date	Interest Rate	Key Terms
Amended and Restated Guaranty Fee Agreement(1)	Jonathan Carroll - LE	Debt	04/01/2017	2.00%	Tied to payoff of LE $25 million Veritex loan; payments 50% cash, 50% Common Stock
Amended and Restated Guaranty Fee Agreement(1)	Jonathan Carroll - LRM	Debt	04/01/2017	2.00%	Tied to payoff of LRM $10 million Veritex loan; payments 50% cash, 50% Common Stock
Refinery Equipment Purchase	LTRI - LE	Operations	07/01/2019	---	LE purchase of two (2) refurbished heat exchangers for $0.08 million each
Dock Tolling Agreement	LMT - LE	Operations	05/24/2016	---	5-year term cancellable by either party any time; LE paid flat reservation fee for tolling volumes up to 84,000 gallons per day; excess tolling volumes subject to increased per gallon rate; terminated 07/01/2019
Jet Fuel Sales Agreement	LEH - LE	Operations	04/01/2019	---	1-year term expiring earliest to occur of 03/01/2020 plus 30-day carryover or delivery of maximum jet fuel quantity; LEH bids on jet fuel contracts under preferential pricing terms due to a HUBZone certification
March Carroll Note (in default)	Jonathan Carroll – Blue Dolphin	Debt	03/31/2017	8.00%	Blue Dolphin working capital; matured 01/01/2019; interest still accruing
March Ingleside Note (in default)	Ingleside – Blue Dolphin	Debt	03/31/2017	8.00%	Blue Dolphin working capital; reflects amounts owed to Ingleside under previous Amended and Restated Tank Lease Agreement; matured 01/01/2019; interest still accruing
June LEH Note (in default)	LEH – Blue Dolphin	Debt	03/312017	8.00%	Blue Dolphin working capital; reflects amounts owed to LEH under Amended and Restated Operating Agreement; reflects amounts owed to Jonathan Carroll under guaranty fee agreements; matured 01/01/2019; interest still accruing
Office Sub-Lease Agreement	LEH - BDSC	Operations	01/01/2018	---	68-month term expiring 08/31/2023; office lease Houston, Texas; includes 6-month rent abatement period; rent approximately $0.02 million per month
Amended and Restated Operating Agreement	LEH – Blue Dolphin / LE	Debt	04/01/2017	---	3-year term; expires 04/01/2020 or notice by either party at any time of material breach or 90 days Board notice; LEH receives management fee of our incurred direct operating expenses plus 5%
Loan and Security Agreement (in default)	LEH - BDPL	Debt	08/15/2016	16.00%	2-year term; $4.0 million principal amount; $0.5 million annual payment; proceeds used for working capital; no financial maintenance covenants; secured by certain BDPL property

(1) 

In November 2019, Mr. Carroll was issued an aggregate of 1,351,851 restricted shares of Common Stock, which represents payment of the common stock component of the guaranty fees for the period May 2017 through October 2019. We recorded an expense of approximately $0.5 million related to the share issuance. As previously disclosed, the Lazarus Parties were prohibited under the GEL Settlement Agreement from making payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements. Following the GEL Settlement, management resumed payments of the common stock component to Jonathan Carroll under the agreements. r. Carroll will receive payment of the common stock component of the guaranty fees on a quarterly basis going forward. Currently, management does not intend on paying Jonathan Carroll the cash portion due to Blue Dolphin’s working capital deficits in the foreseeable future. The cash portion of guaranty fees owed to Jonathan Carroll will continue to be accrued and added to the principal balance of the March Carroll Note. See “Note (16)” to our consolidated financial statements for additional disclosures related to GEL and working capital deficits.

48

Notes to Consolidated Financial Statements

Related-Party Financial Impact

Consolidated Balance Sheets.

Accounts receivable, related party. Accounts receivable, related party represents amounts owed from LEH for the sale of jet fuel under the Jet Fuel Sales Agreement and amounted to $1.4 million and $0 at December 31, 2019 and 2018, respectively. The amounts will be paid under normal business terms. Amounts outstanding relating to the Jet Fuel Sales Agreement can vary significantly period to period based on the timing of the related sales and payments received. See below for amounts owed to LEH under various long-term debt agreements.

Accounts payable, related party. Accounts payable, related party to LMT associated with the Dock Tolling Agreement totaled $0 and $1.5 million at December 31, 2019 and 2018, respectively. Accounts payable, related party to LTRI related to the purchase of refinery equipment totaled $0.2 million and $0 at December 31, 2019 and 2018, respectively.

Long-term debt, related party, current portion (in default).

	December 31,
	2019	2018
	(in thousands)
LEH
June LEH Note (in default)	$-	$611
BDPL Loan Agreement	6,174	5,534
LEH Total	6,174	6,145
Ingleside
March Ingleside Note (in default)	1,004	1,283
Jonathan Carroll
March Carroll Note (in default)	997	1,147
	8,175	8,575
Less: Long-term debt, related party, current portion, in default	(6,001)	(7,041)
Less: Accrued interest payable, related party (in default)	(2,174)	(1,534)
	$-	$-

Consolidated Statements of Operations.

Total revenue from operations.

	Year Ended December 31,
	2019		2018
	(in thousands, except percent amounts)
Refinery operations
LEH	$97,238	31.4%	$98,571	28.9%
Third-Parties	207,686	67.2%	238,467	70.0%
Tolling and terminaling
Third-Parties	4,338	1.4%	3,723	1.1%
	$309,262	100.0%	$340,761	100.0%

Interest expense.

	Year Ended December 31,
	2019	2018
	(in thousands)
Jonathan Carroll
Guaranty Fee Agreements
First Term Loan Due 2034	$443	$456
Second Term Loan Due 2034	183	188
March Carroll Note (in default)	103	56
LEH
BDPL Loan Agreement (in default)	640	631
June LEH Note (in default)	40	17
Ingleside
March Ingleside Note (in default)	63	97
	$1,472	$1,445

Other. Fees associated with the Dock Tolling Agreement with LMT totaled $0.3 million for 2019 compared to $0.6 million for 2018. Lease payments received under the office sub-lease agreement with LEH totaled $0.03 million for both 2019 and 2018. The LEH operating fee totaled $0.6 million for both 2019 and 2018.

49

Notes to Consolidated Financial Statements

(4) 

Revenue and Segment Information

We have two reportable business segments: (i) refinery operations and (ii) tolling and terminaling. Refinery operations relate to the refining and marketing of petroleum products at our 15,000-bpd crude distillation tower. Tolling and terminaling operations relate to tolling and storage terminaling services under third-party lease agreements. Both operations are conducted at the Nixon facility. Corporate and other includes BDSC, BDPL and BDPC.

Revenue from Contracts with Customers

Disaggregation of Revenue. Revenue is presented in the table below under “Segment Information” disaggregated by business segment because this is the level of disaggregation that management has determined to be beneficial to users of our financial statements.

Receivables from Contracts with Customers. Our receivables from contracts with customers are presented as receivables, net on our consolidated balance sheets.

Contract Liabilities. Our contract liabilities from contracts with customers are included in accrued expenses and presented in “Note (9)” to our consolidated financial statements. Substantially all the contract liabilities as of December 31, 2018 were recognized into revenue during the year ended December 31, 2019.

Remaining Performance Obligations. Most of our contracts with customers are spot contracts and therefore have no remaining performance obligations.

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50

Notes to Consolidated Financial Statements

Segment Information. Business segment information for the periods indicated (and as of the dates indicated) was as follows:

	Year Ended December 31,
	2019	2018
	(in thousands)
Net revenue (excluding intercompany fees and sales)
Refinery operations	$304,924	$337,038
Tolling and terminaling	4,338	3,723
Corporate and other	-	-
Total net revenue	309,262	340,761
Intercompany fees and sales
Refinery operations	(2,615)	(3,270)
Tolling and terminaling	2,615	3,270
Corporate and other	-	-
Total intercompany fees	-	-
Operation costs and expenses(1)
Refinery operations	(297,113)	(331,220)
Tolling and terminaling	(1,325)	(1,332)
Corporate and other	(222)	(444)
Total operation costs and expenses	(298,660)	(332,996)
Segment contribution margin
Refinery operations	5,196	2,548
Tolling and terminaling	5,628	5,661
Corporate and other	(222)	(444)
Total segment contribution margin	10,602	7,765
General and administrative expenses, including LEH operating fee
Refinery operations	(1,252)	(1,232)
Tolling and terminaling	(262)	(245)
Corporate and other	(1,145)	(1,795)
Total general and administrative expenses	(2,659)	(3,272)
Depreciation and amortization
Refinery operations	(1,913)	(1,842)
Tolling and terminaling	(396)	(91)
Corporate and other	(181)	-
Total depreciation and amortization	(2,490)	(1,933)
Interest and other non-operating income (expenses), net	1,908	(3,343)
Income (loss) before income taxes	7,361	(783)
Income tax benefit	-	260
Net income (loss)	$7,361	$(523)

(1) 

For the reported periods, operation costs include cost of goods sold. Also, operation costs within: (a) tolling and terminaling includes terminal operating expenses and an allocation of other costs (e.g. insurance and maintenance) and (b) corporate and other includes expenses related to BDSC, BDPC and BDPL.

	December 31,
	2019	2018
	(in thousands)
Capital expenditures
Refinery operations	$1,453	$1,124
Tolling and terminaling	121	905
Corporate and other	-	-
Total capital expenditures	1,574	2,029
Identifiable assets
Refinery operations	51,317	41,116
Tolling and terminaling	18,401	28,446
Corporate and other	1,726	1,115
Total identifiable assets	$71,444	$70,677

51

Notes to Consolidated Financial Statements

(5) 

Concentration of Risk

Bank Accounts

Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain cash balances at financial institutions in Houston, Texas. The FDIC insures certain financial products up to a maximum of $250,000 per depositor. At December 31, 2019 and 2018, we had cash balances (including restricted cash) that exceeded the FDIC insurance limit per depositor of $0.3 million and $1.2 million, respectively.

Key Supplier

Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate. We have a long-term crude supply agreement in place with Pilot. Under the initial term of the crude supply agreement, Pilot will sell us approximately 24.8 million net bbls of crude oil. Thereafter, the crude supply agreement will continue on a one-year evergreen basis. Pilot may terminate the crude supply agreement at any time by providing us 60 days prior written notice. We may terminate the agreement upon the expiration of the initial term or at any time during a renewal term by giving Pilot 60 days prior written notice.

Pilot also stores crude oil at the Nixon facility under a terminal services agreement. Under the terminal services agreement, Pilot stores crude oil at the Nixon facility at a specified rate per bbl of the storage tank’s shell capacity. The terminal services agreement has an initial term that expires April 30, 2020. Thereafter, the terminal services agreement will continue on a one-year evergreen basis. Either party may terminate the terminal services agreement by providing the other party 60 days prior written notice. However, the terminal services agreement will automatically terminate upon expiration or termination of the crude supply agreement.

Our financial health could be adversely affected by defaults in our secured loan agreements, historic net losses, and working capital deficits, which could impact our ability to acquire crude oil and condensate. A failure to acquire crude oil and condensate when needed will have a material effect on our business results and operations.

Significant Customers

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

	Number Significant Customers	% Total Revenue from Operations	Portion of Accounts Receivable December 31
2019	4	96.5%	$1.7 million
2018	4	90.3%	$0.1 million

One of our significant customers is an Affiliate. The Affiliate, LEH, purchases our jet fuel under a Jet Fuel Sales Agreement and bids on jet fuel contracts under preferential pricing terms due to a HUBZone certification. The Affiliate accounted for 31.3% and 28.9% of total revenue from operations in 2019 and 2018, respectively. LEH represented approximately $1.4 million and $0 in accounts receivable at December 31, 2019 and 2019, respectively. The amounts will be paid under normal business terms. Amounts outstanding relating to the Jet Fuel Sales Agreement can vary significantly period to period based on the timing of the related sales and payments received. Amounts owed to LEH under various long-term debt, related-party agreements totaled $6.2 million and $6.1 million at December 31, 2019 and 2018, respectively. See “Note (3)” and “Note (16)” to our consolidated financial statements for additional disclosures related to transactions with Affiliates.

Refined Product Sales. We sell our products primarily in the U.S. within PADD 3. Occasionally we sell refined products to customers that export to Mexico. Total refined product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Year Ended December 31,
	2019		2018
	(in thousands, except percent amounts)
LPG mix	$17	0.0%	$3	0%
Naphtha	59,799	19.6%	82,982	24.6%
Jet fuel	97,239	31.9%	98,570	29.2%
HOBM	66,891	21.9%	80,979	24.1%
AGO	80,978	26.6%	74,504	22.1%
	$304,924	100.0%	$337,038	100.0%

An Affiliate, LEH, purchases our jet fuel. See “Note (3)” and “Note (16)” to our consolidated financial statements for additional disclosures related to Affiliate transactions.

52

Notes to Consolidated Financial Statements

(6) 

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets as of the dates indicated consisted of the following:

	December 31,
	2019	2018
	(in thousands)
Prepaid crude oil and condensate	$1,651	$1,166
Prepaid insurance	417	437
Prepaid eastment renewal fees	121	-
Other prepaids	87	183
	$2,276	$1,786

(7) 

Inventory

Inventory as of the dates indicated consisted of the following:

	December 31,
	2019	2018
	(in thousands)
Crude oil and condensate	$959	$861
AGO	440	276
Chemicals	120	106
Naphtha	95	143
Propane	26	17
LPG mix	5	5
HOBM	-	102
	$1,645	$1,510

(8) 

Property, Plant and Equipment, Net

Property, plant and equipment, net, as of the dates indicated consisted of the following:

	December 31,
	2019	2018
	(in thousands)
Refinery and facilities	$66,317	$63,058
Land	566	566
Other property and equipment	833	747
	67,716	64,371
Less: Accumulated depletion, depreciation, and amortiation	(12,739)	(10,429)
	54,977	53,942
CIP	8,916	10,755
	$63,893	$64,697

We capitalize interest cost incurred on funds used to construct property, plant, and equipment. Capitalized interest is recorded as part of the asset it relates to and is depreciated over the asset’s useful life. Capitalized interest cost, which is included in CIP, was $0.7 million and $1.3 million at December 31, 2019 and 2018, respectively. Capital expenditures for expansion at the Nixon facility are funded by long-term debt from Veritex, revenue from operations, and working capital from Affiliates. Unused amounts for capital expenditures derived from Veritex loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets. See “Note (10)” to our consolidated financial statements for additional disclosures related to working capital deficits and borrowings for capital spending.

53

Notes to Consolidated Financial Statements

(9) 

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities as of the dates indicated consisted of the following:

	December 31,
	2019	2018
	(in thousands)
Unearned revenue from contracts with customers	$1,990	$-
Unearned contract renewal income	500	434
Board of director fees payable	263	273
Other payable	228	265
Taxes payable	183	95
Insurance	159	61
Customer deposits	10	109
Easement payable	-	223
Accrued rent	-	111
	$3,333	$1,571

(10) 

Third-Party Long-Term Debt

Loan Agreements

Loan Description	Original Principal Amount (in millions)	Maturity Date	Monthly Principal and Interest Payment	Interest Rate	Loan Purpose
USDA-Guaranteed Loans
First Term Loan Due 2034 (in default)	$25.0	Jun 2034	$0.2 million	WSJ Prime + 2.75%	Refinance loan; capital improvements
Second Term Loan Due 2034 (in default)	$10.0	Dec 2034	$0.1 million	WSJ Prime + 2.75%	Refinance bridge loan; capital improvements
Notre Dame Debt (in default)	$11.7(1)	Jan 2018	No payments to date; payment rights subordinated(2)	16.00%	Working capital; reduce balance of GEL Final Arbitration Award

(1) 

Original principal amount was $8.0 million; pursuant to a 2017 sixth amendment, the Notre Dame Debt was amended to increase the principal amount by $3.7 million; the additional principal was used to reduce the GEL Final Arbitration Award by $3.6 million.

(2) 

Pursuant to a 2015 subordination agreement, the holder of the Notre Dame Debt agreed to subordinate their right to payments, as well as any security interest and liens on the Nixon facility’s business assets, in favor of Veritex as holder of the First Term Loan Due 2034.

Guarantees and Security

Loan Description	Guarantees	Security
USDA-Guaranteed Loans
First Term Loan Due 2034 (in default)	● 100% USDA-guarantee; ● Jonathan Carroll personal guarantee(1); ● LEH, LRM and Blue Dolphin cross-guarantee	● first priority lien on Nixon facility’s business assets (excluding accounts receivable and inventory); ● assignment of all Nixon facility contracts, permits, and licenses; ● absolute assignment of Nixon facility rents and leases, including tank rental income; ● $1.0 million payment reserve account held by Veritex; and ● $5.0 million life insurance policy on Jonathan Carroll.
Second Term Loan Due 2034 (in default)	● 100% USDA-guarantee; ● Jonathan Carroll personal guarantee(1); ● LEH, LE and Blue Dolphin cross-guarantee	● second priority lien on rights of LE in crude distillation tower and other collateral of LE; ● first priority lien on real property interests of LRM; ● first priority lien on all LRM fixtures, furniture, machinery and equipment; ● first priority lien on all LRM contractual rights, general intangibles and instruments, except with respect to LRM rights in its leases of certain specified tanks for which Veritex has second priority lien; and ● all other collateral as described in the security documents.
Notre Dame Debt (in default)	---	● Subordinated deed of trust that encumbers the crude distillation tower and general assets of LE(2).

(1) 

As a condition of the First Term Loan Due 2034 and Second Term Loan Due 2034, Jonathan Carroll was required to personally guarantee repayment borrowed funds and accrued interest.

(2) 

Pursuant to a 2015 subordination agreement, the holder of the Notre Dame Debt agreed to subordinate their right to payments, as well as any security interest and liens on the Nixon facility’s business assets, in favor of Veritex as holder of the First Term Loan Due 2034.

The USDA, acting through its agencies, administers a federal rural credit program that makes direct loans and guarantees portions of loans made and serviced by USDA-qualified lenders for various purposes. Each USDA guarantee is a full faith and credit obligation of the U.S. with the USDA guaranteeing up to 100% of the principal amount. The lender for a USDA-guaranteed loan, in our case Veritex, is required by regulations to retain both the guaranteed and unguaranteed portions of the loan, to service the entire underlying loan, and to remain mortgage and/or secured party of record. Both the guaranteed and unguaranteed portions of the loan are to be secured by the same collateral with equal lien priority. The USDA-guaranteed portion of a loan cannot be paid later than, or in any way be subordinated to, the related unguaranteed portion. See “Note (3)” to our consolidated financial statements for additional disclosures related to Affiliate agreements and transactions, including long-term debt guarantees.

54

Notes to Consolidated Financial Statements

Representations, Warranties, Covenants, and Defaults

The First Term Loan Due 2034 and Second Term Loan Due 2034 contain representations and warranties, affirmative and negative covenants, and events of default that we consider usual and customary for bank facilities of this type. Specifically, the First Term Loan Due 2034 and Second Term Loan Due 2034 contain debt service coverage ratio, current ratio, and debt to net worth ratio financial covenants. The First Term Loan Due 2034 also requires that a $1.0 million payment reserve account be maintained. There are no financial maintenance covenants associated with the Notre Dame Debt.

Proceeds available for use under the First Term Loan Due 2034 and Second Term Loan Due 2034 were placed in a disbursement account whereby Veritex makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

As described elsewhere in this report, we are in default under our secured loan agreements. Defaults include events of default and financial covenant violations. Defaults under our secured loan agreements permit 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. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2019 and 2018.

Events of Default. In September 2017, Veritex notified obligors of events of default, including, but not limited to, the occurrence of the GEL Final Arbitration Award, associated material adverse effect conditions, failure by LE to replenish a $1.0 million payment reserve account, and the occurrence of events of default by obligors under our other secured loan agreements with Veritex, all of which constituted events of default under our secured loan agreements. Further, Veritex informed obligors that it would consider a final confirmation of the GEL Final Arbitration Award to be a material event of default under the loan agreements. Veritex did not accelerate or call due our secured loan agreements considering these factors. Instead, Veritex expressly reserved all its rights, privileges and remedies related to events of default.

In April 2019, obligors were notified by Veritex that the bank agreed to waive certain covenant violations and forbear from enforcing its remedies under our secured loan agreements subject to: (i) the agreement and concurrence of the USDA and (ii) the replenishment of the payment reserve account on or before August 31, 2019. Following the GEL Settlement, the associated mutual releases became effective and GEL filed a stipulation of dismissal of claims against LE. As of the date of this report, LE had not replenished the payment reserve account and obligors were still in default under our other secured loan agreements with Veritex.

Financial Covenant Violations. At December 31, 2019, LE and LRM were in violation of the debt service coverage ratio, current ratio, and debt to net worth ratio financial covenants under our secured loan agreements with Veritex.

Any exercise by Veritex of its rights and remedies under our secured loan agreements would have a material adverse effect on our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations. In such a case, the trading price of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

We can provide no assurance that: (i) our assets or cash flow will be sufficient to fully repay borrowings under outstanding long-term debt, either upon maturity or if accelerated, (ii) LE and LRM will be able to refinance or restructure the payments on the long-term debt, and/or (iii) Veritex, as first lien holder, will provide future default waivers. Defaults under our 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. See “Note (1)” and “Note (10)” to our consolidated financial statements for additional information regarding defaults under our secured loan agreements and their potential effects on our business, financial condition, and results of operations.

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55

Notes to Consolidated Financial Statements

Outstanding Principal, Debt Issue Costs, and Accrued Interest

Third-party long-term debt (outstanding principal and accrued interest), as of the dates indicated was as follows:

	December 31,
	2019	2018
	(in thousands)
USDA-Guaranteed Loans
First Term Loan Due 2034 (in default)	$21,776	$22,593
Second Term Loan Due 2034 (in default)	9,031	9,353
Notre Dame Debt (in default)	8,617	7,821
Capital lease	-	41
	39,424	39,808
Less: Current portion of long-term debt, net	(33,836)	(34,863)
Less: Unamortized debt issue costs	(1,877)	(2,006)
Less: Accrued interest payable (in default)	(3,711)	(2,939)
	$-	$-

Unamortized debt issue costs associated with USDA-guaranteed loans as of the dates indicated consisted of the following:

	December 31,
	2019	2018
	(in thousands)
USDA-Guaranteed Loans
First Term Loan Due 2034 (in default)	$1,674	$1,674
Second Term Loan Due 2034 (in default)	768	768
Less: Accumulated amortization	(565)	(436)
	$1,877	$2,006

Amortization expense was $0.1 million for both 2019 and 2018.

Accrued interest related to third-party long-term debt, reflected as accrued interest payable in our consolidated balance sheets, as of the dates indicated consisted of the following:

	December 31,
	2019	2018
	(in thousands)
Notre Dame Debt (in default)	$3,639	$2,843
USDA-Guaranteed Loans
First Term Loan Due 2034 (in default)	25	43
Second Term Loan Due 2034 (in default)	47	53
	3,711	2,939
Less: Accrued interest payable (in default)	(3,711)	(2,939)
Long-term Interest Payable, Net of Current Portion	$-	$-

As a result of new ASU guidance related to leases, capital leases are now reported in “Note (13)” as finance leases. See “Note (2),” “Note (3),” and “Note (12”) to our consolidated financial statements for information related to the new lease accounting standard, related-party debt, and debt obligations associated with Pilot.

Future annual third-party long-term debt payments, including interest, which are reflected as current due to defaults under our secured loan agreements:

	Principal and	Debt Issue
Years Ending December 31,	Accrued Interest	Costs	Total
	(in thousands)
2020	$39,424	$(1,877)	$37,547
2021	-	-	-
2022	-	-	-
2023	-	-	-
Thereafter	-	-	-
	$39,424	$(1,877)	$37,547

56

Notes to Consolidated Financial Statements

(11) 

Line of Credit Payable

Line of Credit Agreement

Line of Credit Description	Principal Amount (in millions)	Maturity Date	Monthly Principal and Interest Payment	Interest Rate	Loan Purpose
Amended Pilot Line of Credit	$13.0	May 2020	----	12.00%	GEL Settlement Payment, NPS purchase of crude oil from Pilot, and working capital

Under the Amended Pilot Line of Credit, NPS was required to make a monthly payment to Pilot in each of September and October 2019 in the amount of $0.1 million. The required payments were made.

Guarantees and Security

Loan Description	Guarantees	Security
Amended Pilot Line of Credit	● Blue Dolphin pledged its equity interests in NPS to Pilot to secure NPS’ obligations; ● Blue Dolphin, LE, LRM, and LEH have each guaranteed NPS’ obligations.	● NPS receivables; ● NPS assets, including a tank lease (the “Tank Lease”); ● LRM receivables.

Representations, Warranties, and Covenants

The Amended Pilot Line of Credit contains customary affirmative and negative covenants and events of default. In a May 10, 2019, Subordination and Attornment Agreement between Veritex, LE, NPS, and Pilot, Veritex in its capacity as a secured lender of LE and LRM, agreed to permit the continued performance of obligations under a certain tank lease agreement if it were to foreclose on LE property that NPS was leasing from LE so long as certain conditions were met. The effectiveness of the Subordination and Attornment Agreement is subject to certain conditions, including the agreement and concurrence of the USDA.

Line of credit payable, which represents outstanding principal and accrued interest, as of the dates indicated was as follows:

	December 31,
	2019	2018
	(in thousands)
Amended Pilot Line of Credit	$11,786	$-
Less: Unamortized debt issue costs	(219)	-
Less: Interest payable, short-term	(103)	-
	$11,464	$-

(12) 

AROs

Refinery and Facilities

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Management believes that the refinery and facilities 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 facilities 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.

Pipelines and Facilities and Oil and Gas Properties

We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities assets, as well as the plugging and abandonment of our oil and gas properties. We recorded a discounted liability for the fair value of an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service, and we depreciated the amount added to property and equipment and recognized accretion expense relating to the discounted liability over the remaining life of the asset. At December 31, 2019 and 2018, the liability was fully accreted. See “Note (16)” to our consolidated financial statements for disclosures related to idle iron decommissioning of our pipeline and facilities assets and related risks.

57

Notes to Consolidated Financial Statements

There was no change to our ARO liability from December 31, 2018 to December 31, 2019, as reflected below:

	December 31,
	2019	2018
	(in thousands)
AROs, at the beginning of the period	$2,565	$2,315
Accretion expense	-	265
	2,565	2,580
Less: AROs, current portion	(2,565)	(2,580)
Long-term AROs, at the end of the period	$-	$-

(13) 

Lease Obligations

Adoption of New ASU Guidance

Effective January 1, 2019, we adopted ASU No. 2016-02 “Leases (Topic 842)” and the series of related Accounting Standards Updates that followed. The most significant changes under the new guidance include clarification of the definition of a lease, and the requirements for lessees to recognize a ROU asset and a lease liability for all qualifying leases with terms longer than twelve months in the consolidated balance sheet. Additional disclosures are also required to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases.

We adopted the new lease accounting guidance using the modified retrospective method and applied it to all leases with terms greater than 12 months based on the contract terms in effect as of January 1, 2019. For existing contracts, we carried forward our historical assessment of: (i) whether contracts are or contain leases, (ii) lease classification, and (iii) initial direct costs. For operating leases, we recognized a ROU asset and lease liability as the present value of the fixed lease payments over the lease term. Our finance leases were immaterial prior to the adoption of this guidance, and no change was made to the classification for these leases. Since the leases do not provide a readily determinable discount rate, we use the incremental borrowing rate to discount lease payments to present value.

Lease Obligations

Operating Lease

Office Lease. BDSC has an office lease related to our headquarters office in Houston, Texas. The 68-month operating lease expires in 2023. BDSC has the option to extend the lease term for one additional five (5) year period if notice of intent to extend is provided to the lessor at least twelve (12) months before the end of the current term. An Affiliate, LEH, subleases a portion of this office space.  Sublease income received from LEH totaled $0.03 million for both 2019 and 2018. See “Note (3)” to our consolidated financial statements for additional disclosures related to the Affiliate sub-lease.

Finance Lease

Crane. In January 2018, LE entered a 24-month lease for the purchase of a 20-ton crane for use at the Nixon facility. The lease required a negligible monthly payment and matured in January 2020.

Backhoe Rent-to-Own Agreement. In May 2019,LE entered into a 12-month equipment rental agreement with the option to purchase the backhoe at maturity. The backhoe is being used at the Nixon facility.

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58

Notes to Consolidated Financial Statements

The following table presents the lease-related assets and liabilities recorded on the consolidated balance sheet:

		December 31,
	Balance Sheet Location	2019
		(in thousands)
Assets
Operating lease ROU assets	Operating lease ROU assets	$787
Less: Accumulated amortization on operating lease assets	Operating lease ROU assets	(138)
		649
Finance lease assets	Property and equipment, net	180
Less: Accumulated amortization on finance lease assets	Property and equipment, net	(34)
		146
Total lease assets		795
Liabilities
Current
Operating lease	Current portion of lease liabilities	175
Finance leases	Current portion of lease liabilities	76
		251
Noncurrent
Operating lease	Long-term lease liabilities, net of current	564
Total lease liabilities		$815

Weighted average remaining lease term in years
Operating lease	3.67
Finance leases	0.41
Weighted average discount rate
Operating lease	8.25%
Finance leases	8.25%

The following table presents information related to lease costs for operating and finance leases:

	Year Ended
	December 31,
	2019
	(in thousands)
Operating lease costs	$206
Finance lease costs:
Depreciation of leased assets	21
Interest on lease liabilities	6
Total lease cost	$233

The table below presents supplemental cash flow information related to leases as follows:

Year Ended

December 31,

2019

(in thousands)

Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating lease	$190
Operating cash flows for finance leases	$6
Financing cash flows for finance leases	$45

59

Notes to Consolidated Financial Statements

As of December 31, 2019, maturities of lease liabilities for the periods indicated were as follows:

December 31,	Operating Lease	Financing Leases	Total
	(in thousands)
2020	$175	$76	$251
2021	194	-	194
2022	215	-	215
2023	155	-	155
	$739	$76	$815

Future minimum annual lease commitments that are non-cancelable:

	Operating
December 31,	Lease
	(in thousands)
2020	$230
2021	233
2022	237
2023	161
	$861

(14) 

Income Taxes

Tax Provision

The provision for income tax benefit for the periods indicated was as follows:

	Year Ended December 31,
	2019	2018
	(in thousands)
Current
Federal	$-	$108
State	-	43
Deferred
Change in valuation allowance	-	109
Total provision for income taxes	$-	$260

The state of Texas, TMT is treated as an income tax for financial reporting purposes.

Effective Tax Rate

Our effective tax rate was as follows:

	December 31,
	2019	2018
Expected tax rate	21.00%	(21.00%)
Permanent differences	0.00%	0.00%
State tax	0.00%	(5.10%)
Federal tax	0.00%	(28.10%)
Change in valuation allowance	(21.00%)	21.00%
	0.00%	(33.20%)

60

Notes to Consolidated Financial Statements

Beginning in 2018, our effective tax rate differed from the U.S. federal statutory rate primarily due to AMT credits made refundable by the Tax Cuts and Jobs Act. At the date of enactment of the Tax Cuts and Jobs Act, we re-measured our deferred tax assets and liabilities using a rate of 21%, which is the rate expected to be in place when such deferred assets and liabilities are expected to reverse in the future. The re-measurement was offset by a change in our valuation allowance, resulting in there being no impact on our net deferred tax assets.

Deferred income taxes as of the dates indicated consisted of the following:

	December 31,
	2019	2018
	(in thousands)
Deferred tax assets:
NOL and capital loss carryforwards	$12,463	$11,260
Accrued arbitration award payable	-	2,850
Business interest expense	1,923	704
Start-up costs (crude oil and condensate processing facility)	594	678
ARO liability/deferred revenue	539	542
AMT credit and other	50	108
Total deferred tax assets	15,569	16,142
Deferred tax liabilities:
Basis differences in property and equipment	(6,066)	(5,153)
Total deferred tax liabilities	(6,066)	(5,153)
	9,503	10,989
Valuation allowance	(9,453)	(10,881)
Deferred tax assets, net	$50	$108

Deferred Income Taxes

Deferred income tax balances reflect the effects of temporary differences between the carrying amounts of assets and liabilities and their tax basis, as well as from NOL carryforwards. We state those balances at the enacted tax rates we expect will be in effect when taxes are paid. NOL carryforwards and deferred tax assets represent amounts available to reduce future taxable income.

NOL Carryforwards. Under IRC Section 382, a corporation that undergoes an “ownership change” is subject to limitations on its use of 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 fifty (50) percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). For income tax purposes, we experienced ownership changes in 2005, relating to a series of private placements, and in 2012, because of a reverse acquisition, that limit the use of pre-change NOL carryforwards to offset future taxable income. In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $16.3 million in NOL carryforwards that were generated prior to the ownership change to an annual use limitation of approximately $0.6 million per year. Unused portions of the annual use limitation amount may be used in subsequent years. Because of the annual use limitation, approximately $6.7 million in NOL carryforwards that were generated prior to the 2012 ownership change will expire unused. NOL carryforwards that were generated after the 2012 ownership change and prior to 2018 are not subject to an annual use limitation under IRC Section 382 and may be used for a period of 20 years in addition to available amounts of NOL carryforwards generated prior to the ownership change. NOL carryforwards that were generated after 2017 may only be used to offset 80% of taxable income and are carried forward indefinitely.

61

Notes to Consolidated Financial Statements

NOL Carryforwards. NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused because of the IRC Section 382 limitation):

	Net Operating Loss Carryforward
	Pre-Ownership Change	Post-Ownership Change	Total
	(in thousands)
Balance at December 31, 2017	$9,614	$30,219	$39,833
Net operating losses	-	7,116	7,116
Balance at December 31, 2018	9,614	37,335	46,949
Net operating losses	-	5,723	5,723
Balance at December 31, 2019	$9,614	$43,058	$52,672

Valuation Allowance. 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, 2019 and 2018, 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, 2019 and 2018.

(15) 

Earnings Per Share

A reconciliation between basic and diluted income per share for the periods indicated was as follows:

	Year Ended December 31,
	2019	2018
	(in thousands, except share and per share amounts)
Net income (loss)	$7,361	$(523)
Basic and diluted income (loss) per share	$0.66	$(0.05)
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock	11,156,995	10,935,787

Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for 2019 and 2018 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

62

Notes to Consolidated Financial Statements

(16) 

Commitments and Contingencies

Legal Matters

Resolved - GEL Settlement. As previously disclosed, GEL was awarded the GEL Final Arbitration Award in the aggregate amount of $31.3 million. In July 2018, the Lazarus Parties and GEL entered into the GEL Settlement Agreement. The GEL Settlement Agreement was subsequently amended five (5) times to extend the GEL Settlement Payment Date and/or modify certain terms related to the GEL Interim Payments or the GEL Settlement Payment. During the period September 2017 to August 2019, GEL received the following amounts from the Lazarus Parties to reduce the outstanding balance of the GEL Final Arbitration Award:

	(in millions)
Initial payment (September 2017)	$3.7
GEL Interim Payments (July 2018 to April 2019)	8.0
Settlement Payment (Multiple Payments May 7 to 10, 2019)	10.0
Deferred Interim Installment Payments (June 2019 to August 2019)	0.5
	$22.2

The GEL Settlement Effective Date occurred on August 23, 2019. As a result of the GEL Settlement: (i) the mutual releases became effective, (ii) GEL filed a stipulation of dismissal of claims against LE, and (iii) Blue Dolphin recognized a $9.1 million gain on the extinguishment of debt on its consolidated statements of operations in the third quarter of 2019. Until the GEL Settlement occurred, the debt was reflected on Blue Dolphin’s consolidated balance sheets as accrued arbitration award payable. At December 31, 2019 and 2018, accrued arbitration award payable was $0 and $21.1million, respectively.

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 exercises its rights and remedies due to defaults under our secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

Defaults Under Secured Loan Agreements

See “Note (1)” and “Note (10)” to our consolidated financial statements for additional disclosures related to defaults under our secured loan agreements.

Amended and Restated Operating Agreement

See “Note (3)” to our consolidated financial statements for additional disclosures related to operation and management of all Blue Dolphin properties by an Affiliate under the Amended and Restated Operating Agreement.

Financing Agreements and Guarantees

Indebtedness. See “Note (3),” “Note (10),” and “Note (11)” to our consolidated financial statements for disclosures related to Affiliate and third-party indebtedness.

Guarantees. Affiliates provided guarantees on certain debt of Blue Dolphin and its subsidiaries. The maximum amount of any guarantee is equal to the principal amount and accrued interest, which amounts are reduced as payments are made. See “Note (3),” “Note (10),” and “Note (11)” to our consolidated financial statements for additional disclosures related to Affiliate and third-party guarantees associated with indebtedness and associated risk factors.

Health, Safety and Environmental Matters

Our operations are subject to extensive federal, state, and local environmental, health, and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum products and hazardous substances; the emission and discharge of materials into the environment; waste management; characteristics and composition of jet fuel and other products; and the monitoring, reporting and control of air emissions. Our operations also require numerous permits and authorizations under various environmental, health, and safety laws and regulations. Failure to obtain and comply with these permits or environmental, health, or safety laws generally could result in fines, penalties or other sanctions, or a revocation of our permits.

Nixon Facility Expansion

Wehave made and will continue to make capital and efficiency improvements at the Nixon facility. Therefore, we incurred and will continue to incur capital expenditures related to these improvements, which include, among other things, facility and land improvements, installation of new and/or refurbished refinery process equipment, and completion of a petroleum storage tank.

63

Notes to Consolidated Financial Statements

Idle Iron

BDPL has pipeline and facilities assets that are subject to BSEE’s idle iron regulations. BSEE mandates lessees and rights-of-way holders to permanently abandon and/or remove platforms and other structures when they are no longer useful for operations. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, BOEM evaluates an operator’s financial ability to carry out present and future obligations to determine whether the operator must provide additional security beyond the minimum bonding requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by BOEM.

BDPL has historically maintained $0.9 million in financial assurance to BOEM for the decommissioning of its trunk pipeline offshore in federal waters. Following an agency restructuring of the financial assurance program, in March 2018 BOEM ordered BDPL to provide supplemental pipeline bonds totaling $4.8 million for five (5) existing pipeline rights-of-way within sixty (60) calendar days. In June 2018, BOEM issued BDPL INCs for each right-of-way that failed to comply. BDPL appealed the INCs to the IBLA, and the IBLA granted multiple extension requests that extended BDPL’s deadline for filing a statement of reasons for the appeal with the IBLA. In December 2018, BSEE issued an INC to BDPL for failure to flush and fill Pipeline Segment No. 13101.

On August 9, 2019, BDPL timely filed its statement of reasons for the appeal with the IBLA. Management met with BOEM and BSEE on August 15, 2019. BSEE proposed that BDPL re-submit permit applications for pipeline and platform decommissioning, along with a safe boarding plan for the platform, within six (6) months (no later than February 15, 2020), and develop and implement a safe boarding plan for submission with such permit applications. BDPL timely submitted permit applications for decommissioning and removal of the subject offshore assets on February 11, 2020. Further, BSEE proposed that BDPL complete approved, permitted work within 12 months (no later than August 15, 2020).  Considering BDPL’s August 2019 meeting with BOEM and BSEE, BDPL requested a stay in the IBLA matter until August 2020. The Office of the Solicitor of the U.S. Department of the Interior was agreeable to a 10-day extension while it conferred with BOEM on BDPL’s stay request. In late October 2019, BDPL filed a motion to request the 10-day extension, which motion was subsequently granted by the IBLA. The solicitor’s office consented to an additional 14-day extension for BDPL to file its reply, and BDPL filed a motion to request the 14-day extension in November 2019. The solicitor’s office indicated that BOEM would not consent to further extensions. However, the solicitor’s office signaled that BDPL’s adherence to the milestones identified in the August 15, 2019 meeting may help in future discussions with BOEM related to the INCs. BDPL reasonably expects that successful completion of its decommissioning obligations will significantly reduce or eliminate the amount of financial assurance required, which may serve to partially or fully resolve the INCs.

BDPL reasonably expects that successful completion of its decommissioning obligations prior to BSEE’s August 2020 deadline will significantly reduce or eliminate the amount of financial assurance required by BOEM, which may serve to partially or fully resolve the INCs. BDPL expects to complete approved, permitted decommissioning work by the BSEE August 2020 deadline. If decommissioning of the assets is not completed by the allowable deadline, BDPL will be subject to vigorous regulatory oversight and enforcement, including but not limited to failure to correct an INC, civil penalties, and revocation of BDPL’s operator designation, which may have a material adverse effect on our earnings, cash flows and liquidity.

BDPL’s pending appeal of the INCs does not relieve BDPL of its obligations to provide additional financial assurance or of BOEM’s authority to impose financial penalties. If BDPL is required by BOEM to provide significant additional 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. We are currently unable to predict the outcome of the INCs. Accordingly, we have not recorded a liability on our consolidated balance sheet as of December 31, 2019.

At December 31, 2019 and 2018, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to BOEM. As of December 31, 2019, we maintained $2.6 million in AROs related to abandonment of these assets.

(17) 

Subsequent Events

In early March 2020, crude oil prices declined significantly in response to worldwide oil demand concerns due to the economic impacts of COVID-19, which has also negatively impacted numerous other industries, domestic and international. The extent to which these events may impact our business will depend on future developments, which are highly uncertain and cannot be predicted at this time. Further, the duration and intensity of these impacts and resulting disruption to our operations is uncertain and we will continue to assess the financial impact.

64

Internal Controls and Procedures

ITEM 9.  

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Management’s Report on Internal Control over Financial Reporting

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s Assessment. Management, under the supervision and with the participation of our Chief Executive Officer (principal executive officer, principal financial officer, and principal accounting officer), assessed the effectiveness of our internal controls over financial reporting at December 31, 2019. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations of the Treadway Commission Framework and SOX Compliance. Relating to such evaluation, management concluded that our internal controls over financial reporting were ineffective at December 31, 2019 due to certain material weaknesses and/or significant deficiencies as described below:

● Significant deficiency – There is currently not a process in place for formal review of manual journal entries.

● Material weakness – The company currently lacks resources to handle complex accounting transactions. This can result in errors related to the recording, disclosure and presentation of consolidated financial information in quarterly, annual, and other filings. Current year audit procedures resulted in significant adjustments related to the accounting for a certain stock issuance in payment of related party debt, as well as deferred revenue relating to consideration received from a supplier.

We intend to take the necessary measures to implement formal policies, improve processes, document procedures, and better define segregation of duties to improve financial reporting. These actions will be subject to ongoing senior management review, as well as Audit Committee oversight. Although we plan to complete remediation as quickly as possible, we cannot at this time estimate how long it will take, and our initiatives may not prove to be successful in fully remediating the identified weakness and deficiency.

Changes in Internal Control over Financial Reporting. During the period covered by this report there have been no changes in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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

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Other Information

ITEM 9B.  OTHER INFORMATION

Sales of Unregistered Securities

Set forth below is information regarding the sale or issuance of shares of Common Stock by us for the years ended December 31, 2019 and 2018 that were not registered under the Securities Act of 1933:

● 

On November 14, 2019, we issued an aggregate of 1,351,851 restricted shares of Common Stock to Jonathan Carroll pursuant to guaranty fee agreements. The issuance represents payment of the common stock component of the guaranty fees for the period May 2017 through October 2019, which payments were not permissible under the GEL Settlement Agreement. We recorded an expense of approximately $0.5 million related to the share issuance. Mr. Carroll will receive payment of the common stock component of the guaranty fees on a quarterly basis going forward. The cash portion of guaranty fees owed to Jonathan Carroll will continue to be accrued and added to the principal balance of the March Carroll Note.

● 

On October 18, 2018, we issued an aggregate of 50,001 restricted shares of Common Stock to certain of our non-employee, independent directors for services rendered to the Board for the period January 1, 2018 to March 31, 2018. At March 31, 2018, the grant date market value cost basis was $0.60 per share.

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

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Directors and Officers and Corporate Governance

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Overview

Blue Dolphin was formed in 1986 as a Delaware corporation and is traded on the OTCQX under the ticker symbol “BDCO”. Affiliates control approximately 82% of the voting power of our Common Stock. An Affiliate operates and manages all Blue Dolphin properties and funds working capital requirements during periods of working capital deficits, and an Affiliate is a significant customer of our refined products. Blue Dolphin and certain of its subsidiaries are currently parties to a variety of agreements with Affiliates and a counterparty. See “Item 1A.” and “Note (3)” to our consolidated financial statements for additional disclosures related to Affiliate risk factors, Affiliate agreements and arrangements, and risks associated with working capital deficits.

Board Composition

The amended and restated bylaws of Blue Dolphin provide that the Board shall consist of five (5) members, with the precise number to be determined from time to time by the Board, except that no decrease in the number shall have the effect of shortening the term of an incumbent director. The Board currently has five (5) directors, each serving until the next annual meeting of stockholders to be held by Blue Dolphin. The following sets forth, at March 30, 2020, each director’s name, age, principal occupation and directorships during the past five (5) years, as well as their relevant knowledge and experience that led to their appointment to the Board:

Name, Age Principal Occupation and Directorships During Past 5 Years	Knowledge and Experience
Jonathan P. Carroll, 58 Blue Dolphin Chairman of the Board (since 2014) Chief Executive Officer, President, Assistant Treasurer and Secretary (since 2012) LEH President (since 2006) and Majority Owner Together, LEH and Jonathan Carroll owned approximately 82% of our outstanding Common Stock as of the filing date of this report. Mr. Carroll has served on Blue Dolphin’s Board since 2014. He is currently Chairman of the Board. Since 2004, he has served on the Board of Trustees of the Salient Fund Group, and has served on the compliance, audit and nominating committees of several of Salient’s private and public closed-end and mutual funds. Mr. Carroll previously served on the Board of Directors of the General Partner of LRR Energy, L.P. (NYSE: LRE) from January 2014 until its merger withVanguard Natural Resources, LLC in October 2015.	Mr. Carroll earned a Bachelor of Arts degree in Human Biology and a Bachelor of Arts degree in Economics from Stanford University, and he completed a Directed Reading in Economics at Oxford University. Based on his educational and professional experiences, Mr. Carroll possesses particular knowledge and experience in business management, finance and business development that strengthen the Board’s collective qualifications, skills and experience.
Ryan A. Bailey, 44 Pacenote Capital Managing Partner (since August 2019) and Co-founder Children’s Health System of Texas Head of Investments (2014 to August 2019) The Meadows Foundation Investment Officer/Interim Chief Investment Officer (2006 to 2014) Mr. Bailey was appointed to Blue Dolphin’s Board in November 2015.  He is currently a member of the Audit and Compensation Committees.  He also serves as an advisor and mentor to Texas Wall Street Women, a non-profit member organization; is a member of the advisory board of Solovis, Inc., an investment software company; and serves as a Board member for the Texas Hedge Fund Association.	Mr. Bailey earned a Bachelor of Arts in Economics from Yale University and completed a graduate course in tax planning from the Yale School of Management.  He holds professional credentialing as a Chartered Financial Analyst (CFA), Financial Risk Manager (FRM), Chartered Alternative Investment Analyst (CAIA) and Chartered Market Technician (CMT). Based on his educational and professional experiences, Mr. Bailey possesses particular knowledge and experience in finance, financial analysis and modeling, investment management, risk assessment and strategic planning that strengthen the Board’s collective qualifications, skills and experience.

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Directors and Officers and Corporate Governance

Name, Age Principal Occupation and Directorships During Past 5 Years	Knowledge and Experience
Amitav Misra, 42 Arundo Analytics, Inc. General Manager Americas (since 2018) Vice President of Marketing (since 2017) Cardinal Advisors Partner (2014 to 2017) and Founder Taxa, Inc. President, Director and Chief Operating Officer (2012 to 2014) EnerNOC, Inc. Channel Manager (2011 to 2012) Mr. Misra has served on Blue Dolphin’s Board since 2014.  He is currently a member of the Audit and Compensation Committees.  Mr. Misra serves as an advisor to several energy, technology and private investment companies.  He is also a director of the Houston Center for Literacy, a non-profit organization.	Mr. Misra earned a Bachelor of Arts in Economics from Stanford University and holds FINRA Series 79 and Series 63 licenses. Mr. Misra possesses particular knowledge and experience in economics, business development, private equity, and strategic planning that strengthen the Board’s collective qualifications, skills and experience.
Christopher T. Morris, 58 Impact Partners LLC President (since 2017) Tatum (a Randstad Company) New York Managing Partner (2013 to 2017) MPact Partners LLC President (2011 to 2013) Mr. Morris has served on Blue Dolphin’s Board since 2012; he is currently Chairman of the Audit and Compensation Committees.	Mr. Morris earned a Bachelor of Arts in Economics from Stanford University and a Masters in Business Administration from the Harvard Business School. Based on his educational and professional experiences, Mr. Morris possesses particular knowledge and experience in business management, finance, strategic planning and business development that strengthen the Board’s collective qualifications, skills and experience.
Herbert N. Whitney, 79 Wildcat Consulting, LLC President (since 2006) and Founder Mr. Whitney has served on Blue Dolphin’s Board since 2012. He previously served on the Board of Directors of Blackwater Midstream Corporation, the Advisory Board of Sheetz, Inc., as Chairman of the Board of Directors of Colonial Pipeline Company, and as Chairman of the Executive Committee of the Association of Oil Pipelines.	Mr. Whitney has more than 40 years of experience in pipeline operations, crude oil supply, product supply, distribution and trading, as well as marine operations and logistics having served as the President of CITGO Pipeline Company and in various general manager positions at CITGO Petroleum Corporation. He earned his Bachelor of Science in Civil Engineering from Kansas State University. Based on his educational and professional experiences, he possesses extensive knowledge in the supply and distribution of crude oil and petroleum products, which strengthens the Board’s collective qualifications, skills and expertise.

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Directors and Officers and Corporate Governance

This table shows, as of March 30, 2020, the name and age of each executive officer, as well as their principal occupation during the past five (5) years:

Name	Position	Since	Age
Jonathan P. Carroll	Chief Executive Officer, President, Assistant Treasurer, and Secretary (Principal Executive Officer, Principal Financial Officer, and Principal Accounting Officer)	2012	58

Mr. Carroll was appointed Chairman of the Board of Blue Dolphin in 2014, and he was appointed Chief Executive Officer, President, Assistant Treasurer and Secretary of Blue Dolphin in 2012. He has also served as President of LEH since 2006 and is its majority owner. Together, LEH and Jonathan Carroll own 82.1% of Blue Dolphin’s Common Stock as of the Record Date.  Before founding LEH, Mr. Carroll was a private investor focused on direct debt and equity investments, primarily in distressed assets.  Since 2004, he has served on the Board of Trustees of Salient Fund Group, and has served on the compliance, audit and nominating committees of several of Salient’s private and public closed-end and mutual funds.  Mr. Carroll previously served on the Board of Directors of the General Partner of LRR Energy, L.P. (NYSE: LRE) from January 2014 until its merger with Vanguard Natural Resources, LLC in October 2015. He earned a Bachelor of Arts degree in Human Biology and a Bachelor of Arts degree in Economics from Stanford University, and he completed a Directed Reading in Economics at Oxford University.

Mr. Tommy L. Byrd served as our Chief Financial Officer from 2015 to 2018 and as our Interim Chief Financial Officer from 2012 to 2015. He served as our Treasurer and Assistant Secretary from 2012 to 2018. Mr. Byrd resigned effective December 31, 2018.

Family Relationships between Directors and Officers

At March 30, 2020, there were no family relationships between any of our directors or executive officers.

Structure and Meetings of the Board and Board Committees

Board

The Board consists of Messrs. Carroll, Bailey, Misra, Morris and Whitney with Mr. Carroll serving as Chairman. During 2019, the Board met three (3) times. The Board has two standing committees, the Audit Committee and the Compensation Committee.

Audit Committee

The Audit Committee consists of Messrs. Morris, Bailey, and Misra, with Mr. Morris serving as Chairman. During 2019, the Audit Committee met four (4) times. The Board has affirmatively determined that all members of the Audit Committee are independent under OTCQX and SEC rules and that each of Messrs. Morris and Bailey qualifies as an Audit Committee Financial Expert. The Audit Committee's duties include overseeing financial reporting and internal control functions. The Audit Committee’s written charter is available on our corporate website (http://www.blue-dolphin-energy.com).

Compensation Committee

The Compensation Committee consists of Messrs. Morris, Bailey, and Misra, with Mr. Morris serving as Chairman. During 2019, the Compensation Committee did not meet. The Board has affirmatively determined that all members of the Compensation Committee are independent under OTCQX rules. The Compensation Committee’s duties include setting and overseeing our compensation policies, as well as reviewing and recommending to the Board for its approval all compensation for the Chief Executive Officer, other senior executives, and directors. The Compensation Committee’s written charter is available on our corporate website (http://www.blue-dolphin-energy.com).

Nominating Committee

Given the small size of the Board, the Board adopted a ‘Board Nomination Procedures’ policy in lieu of appointing a standing nominating committee. The Audit Committee uses the policy to perform in a similar function as a standing nominating committee. The policy is used by the independent directors when choosing nominees to stand for election. The Board will consider for possible nomination qualified nominees recommended by stockholders in accordance with Blue Dolphin’s Certificate of Incorporation. As addressed in the ‘Board Nomination Procedures’ policy, the manner in which independent directors evaluate nominees for director as recommended by a stockholder is the same as that for nominees received from other sources.

The Board endeavors to nominate qualified directors that will make important contributions to the Board and to Blue Dolphin. The Board generally requires that nominees be persons of sound ethical character, be able to represent all stockholders fairly, have demonstrated professional achievements, have meaningful experience, and have a general appreciation of the major business issues facing Blue Dolphin. The Board also considers issues of diversity and background in its selection process, recognizing that it is desirable for its membership to have differences in viewpoints, professional experiences, educational backgrounds, skills, race, gender, age and national origin.

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Directors and Officers and Corporate Governance

Director Attendance at Annual Meeting

Given the small size of the Board, director attendance at our annual meeting of stockholders is encouraged but not required. Mr. Carroll was the only director present at the 2019 annual meeting of stockholders.

Leadership Structure

Blue Dolphin is led by Mr. Carroll, who has served as our Chief Executive Officer and President since 2012 and as our Chairman of the Board since 2014. Having a single leader is commonly used by other public companies in the United States, and we believe it is effective for Blue Dolphin as well. This leadership structure demonstrates to our personnel, customers, and stockholders that we are under strong leadership, with a single person setting the tone and having primary responsibility for managing our operations, and it eliminates the potential for confusion or duplication of efforts. We do not believe that appointing an independent Board chairman, or a permanent lead director, would improve upon the performance of the Board.

Risk Oversight

Our Board is involved in overseeing Blue Dolphin’s risk management. The two standing Board committees provide appropriate risk oversight. The Audit Committee oversees the accounting and financial reporting processes, as well as compliance, internal control, legal and risk matters. The Compensation Committee oversees compensation policies, including the approval of compensation for directors and management. We believe that the processes established to report and monitor systems for material risks applicable to us are appropriate and effective.

Code of Ethics and Code of Conduct

In compliance with the Sarbanes-Oxley Act of 2002, the Board adopted a code of ethics policy and a code of conduct policy. The Audit Committee established procedures to enable anyone who has a concern about our conduct, policies, accounting, internal control over financial reporting, and/or auditing matters to communicate that concern directly to the Chairman of the Audit Committee. The code of ethics and code of conduct policies are available to any stockholder, without charge, upon written request to Blue Dolphin Energy Company, Attention: Audit Committee Chairman, 801 Travis Street, Suite 2100, Houston, Texas 77002 or such other contact information for the Audit Committee Chairman that we may post on our website from time to time. Our code of ethics and code of conduct policies are also available on our website (http://www.blue-dolphin-energy.com). Any amendments or waivers to provisions of our code of ethics or code of conduct will be disclosed on Form 8-K as filed with the SEC and/or posted on our website.

Communicating with Directors

As the Board does not receive a large volume of correspondence from stockholders, at this time, there is no formal process by which stockholders can communicate with the Board. Instead, any stockholder who desires to contact the Board or specific members of the Board may do so by writing to: Blue Dolphin Energy Company, Attention: Secretary for the Board, 801 Travis Street, Suite 2100, Houston, Texas 77002. Currently, all communications addressed in such manner are sent directly to the indicated directors. In the future, if the Board adopts a formal process for determining how communications are to be relayed to directors, that process will be disclosed on Form 8-K as filed with the SEC and/or posted on our website (http://www.blue-dolphin-energy.com).

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Executive Compensation

ITEM 11.  EXECUTIVE COMPENSATION

Executive Compensation Policy and Procedures

An Affiliate operates and manages all Blue Dolphin properties pursuant to the Amended and Restated Operating Agreement. Services under the Amended and Restated Operating Agreement include personnel serving in a variety of capacities, including, but not limited to corporate executives. All personnel work for and are paid by the Affiliate. See “Note (3)” to our consolidated financial statements for additional disclosures related to Affiliate arrangements.

Compensation for Named Executives

Under the Amended and Restated Operating Agreement, compensation paid to our principal executive officer, principal financial officer, and the most highly compensated executive officers other than the principal executive officer and principal financial officer whose annual salary exceeded $100,000 (collectively, the “Named Executive Officers”) for the periods indicated was as follows:

Summary Compensation Table

Name and Principal Position	Year	Salary	Total
		(in thousands)
Jonathan P. Carroll	2019	$-	$-
Chief Executive Officer and President	2018	-	-
Tommy L. Byrd(1)	2019	-	-
Chief Financial Officer	2018	$177	$177

(1) 

Mr. Byrd resigned effective December 31, 2018.

Compensation Risk Assessment

The Affiliate’s approach to compensation practices and policies applicable for executive and non-executive personnel throughout our organization is consistent with the base pay market median for each position. The Affiliate believes its practices and policies in this regard are not reasonably likely to have a materials adverse effect on us.

Outstanding Equity Awards

None.

Director Compensation Policy and Procedures

Although Jonathan Carroll is a director of Blue Dolphin, his services as Chief Executive Officer are provided under the Amended and Restated Operating Agreement (see above under “Executive Compensation Policy and Procedures.”) Therefore, we do not have any directors that are also employed by Blue Dolphin. The Compensation Committee reviews and recommends to the Board for its approval all compensation for the directors.

Compensation for Non-Employee Directors

Non-employee, independent directors receive compensation for their service on the Board of $40,000 per year. Compensation is earned in Common Stock and cash on a quarterly rotating basis, as follow:

Fair Market Value	Period Services Rendered	Payment Method
$10,000	January 1 – March 31 (First Quarter)	Common stock
$10,000	April 1 – June 30 (Second Quarter)	Cash
$10,000	July 1 – September 30 (Third Quarter)	Common stock
$10,000	October 1 – December 31 (Fourth Quarter)	Cash

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Executive Compensation

For the first and third quarters, the number of shares of Common Stock to be issued is determined by the closing price of Blue Dolphin’s Common Stock on the last trading day in the respective quarterly period and such closing price is the cost basis for such issuance. The shares of Common Stock are subject to resale restrictions applicable to restricted securities and securities held by affiliates under federal securities laws.

Non-employee, independent directors also earn additional compensation for serving on the Audit Committee. The chairman of the Audit Committee earns an additional $2,500 in cash in each of the second and fourth quarters of the year, for a total of $5,000 annually. Members of the Audit Committee earn an additional $1,250 in cash in each of the second and fourth quarters of the year, for a total of $2,500 annually. Non-employee, independent directors serving on the Compensation Committee do not earn any additional compensation for their service as directors. Non-employee, independent directors are reimbursed for reasonable out-of-pocket expenses related to in-person meeting attendance.

At December 31, 2019, non-employee, independent directors had not been paid the cash portion of their compensation since 2015 and the common stock portion of their compensation following the first quarter 2018 service period due to defaults under our secured loan agreements, historic net losses, and working capital. However, as of the filing date of this report, non-employee, independent directors had been paid the outstanding cash portion of accrued director fees. Non-employee, independent directors will receive payment of the common stock portion of director fees going forward. Unpaid cash fees are reflected within accrued expenses and other current liabilities on our consolidated balance sheets. See “Note (9) Accrued Expenses and Other Current Liabilities” to our consolidated financial statements for additional disclosures related to board of director fees payable.

Accrued and Unpaid Non-Employee, Independent Director Compensation

	Years Ended December 31,
	2019			2018
	(in thousands)
Name	Cash	Stock(1)(2)	Total(3)	Cash	Stock(1)(2)	Total(3)
Christopher T. Morris	$25,000	$20,000	$45,000	$25,000	$20,000	$45,000
Ryan A. Bailey	22,500	20,000	42,500	22,500	20,000	42,500
Amitav Misra	22,500	20,000	42,500	22,500	20,000	42,500
	$70,000	$60,000	$130,000	$70,000	$60,000	$130,000

(1)	At December 31, 2019 and 2019, Messrs. Morris, Bailey, Misra and Whitney had total restricted awards of Common Stock outstanding of 75,026, 60,676, 66,767 and 9,683, respectively.
(2)	At March 31, 2018, the grant date market value cost basis was $0.60 per share.
(3)	At December 31, 2019 and 2018, Messrs. Morris, Bailey and Misra were collectively owed $263,000 and $273,000, respectively, in accrued and unpaid compensation for director fees.

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72

Security Ownership and Related Stockholder Matters

ITEM 12. 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners

The table below sets forth information at December 31, 2019 with respect to persons or groups known to us to be the beneficial owners of more than five percent (5%) of our common stock. Unless otherwise indicated, each named party has sole voting and dispositive power with respect to such shares.

Title of Class	Name of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class(1)
Common Stock	LEH	8,426,456	68.4%
	801 Travis Street, Suite 2100
	Houston, Texas 77002

(1) 

Based upon 12,327,365 shares of Common Stock issued and outstanding at December 31, 2019.

Security Ownership of Management

The table below sets forth information at December 31, 2019 with respect to: (i) directors, (ii) executive officers and (iii) directors and executive officers as a group beneficially owning our common stock. Unless otherwise indicated, each of the following persons has sole voting and dispositive power with respect to such shares.

Title of Class	Name of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class(1)
Common Stock	Jonathan P. Carroll(2)	10,115,151	82.1%
Common Stock	Christopher T. Morris	75,026	*
Common Stock	Amitav Misra	66,767	*
Common Stock	Ryan A. Bailey	60,676	*
Common Stock	Herbert N. Whitney	9,683	*
Directors/Nominees and Executive Officers as a Group (5 Persons)		10,327,303	83.8%

(1) 

Based upon 12,327,365 shares of Common Stock issued and outstanding at December 31, 2019. At December 31, 2019, there were no options outstanding, no options exercisable or no shares of common stock reserved for issuance under the 2000 Stock Incentive Plan.

(2) 

Includes 8,426,456 shares issued to LEH. Jonathan Carroll has an approximate 60% ownership interest in LEH.

* Less than 1%.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors, executive officers, and stockholders who own more than ten percent (10%) of our Common Stock to file reports of stock ownership and changes in ownership with the SEC and to furnish us with copies of all such reports as filed. Based solely on a review of the copies of the Section 16(a) reports furnished to us, we are unaware of any late filings made during 2019 and 2018.

Equity Compensation Plan Information

None.

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Related Party Transactions, Director Independence and Accounting Fees

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related-Party Transactions

See “Note (3)” to our consolidated financial statements for disclosures related to relationships we have with Affiliates.

Director Independence

The Board has affirmatively determined that each of its members, except for Messrs. Carroll and Whitney, are independent and have no material relationship with us (either directly or indirectly or as a stockholder or officer of an organization that has a relationship with us), and that all members of the Audit and Compensation Committees are independent, pursuant to OTCQX and SEC rules. Mr. Whitney currently serves as a consultant to an Affiliate.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

Fees we paid to UHY related to accounting fees and services for the periods indicated were as follow:

	Year Ended December 31,
	2019	2018
	(in thousands)
Audit fees	$247	$138
Audit-related fees	-	-
Tax fees	-	-
	$247	$138

Audit fees for 2019 and 2018 related to the audit of our consolidated financial statements and the review of our quarterly reports that are filed with the SEC. Each year the Audit Committee pre-approves all audit services provided to us by our registered public accounting firm. Such approval is in the form of an engagement letter. Non-audit services must also be pre-approved by the Audit Committee prior to engagement of such services.

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Exhibit List

PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibits and Financial Statement Schedules

Following is a list of documents filed as part of this report:

● 

Consolidated balance sheets, consolidated statements of operations, consolidated statements of shareholders’ equity (deficit), and consolidated statements of cash flows, which appear in “Item 8.”

● 

Exhibits as listed in the exhibit index of this report, which is incorporated herein by reference.

ITEM 16.  FORM 10-K SUMMARY

Not applicable.

Exhibits Index

No.  Description

3.1  Amended and Restated Certificate of Incorporation of Blue Dolphin (incorporated by reference to Exhibit 3.1 filed with Blue Dolphin’s Form 8-K on June 2, 2009, Commission File No. 000-15905)

3.2  Amended and Restated By-Laws of Blue Dolphin (incorporated by reference to Exhibit 3.1 filed with Blue Dolphin’s Form 8-K on December 26, 2007, Commission File No. 000-15905)

4.1  Specimen Stock Certificate (incorporated by reference to exhibits filed with Blue Dolphin’s Form 10-K on March 30, 1990, Commission File No. 000-15905)

4.2  Form of Promissory Note issued pursuant to the Note and Warrant Purchase Agreement dated September 8, 2004 (incorporated by reference to Exhibit 4.1 filed with Blue Dolphin’s Form 8-K on September 14, 2004, Commission File No. 000-15905)

4.3	Promissory Note of Lazarus Louisiana Refinery II, LLC, payable to Blue Dolphin dated July 31, 2009 (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 8-K on August 6, 2009, Commission File No. 000-15905)
4.4	Description of company securities.

10.1* Blue Dolphin 2000 Stock Incentive Plan (incorporated by reference to Appendix 1 filed with Blue Dolphin’s Proxy Statement on Form DEF 14A on April 20, 2000, Commission File No. 000-15905)

10.2* First Amendment to the Blue Dolphin 2000 Stock Incentive Plan (incorporated by reference to Appendix B filed with Blue Dolphin’s Proxy Statement on Form DEF 14A on April 16, 2003, Commission File No. 000-15905)

10.3* Second Amendment to the Blue Dolphin 2000 Stock Incentive Plan (incorporated by reference to Appendix A filed with Blue Dolphin’s Proxy Statement on Form DEF 14A on April 27, 2006, Commission File No. 000-15905)

10.4*	Fourth Amendment to the Blue Dolphin 2000 Stock Incentive Plan (incorporated by reference to Exhibit B filed with Blue Dolphin’s Proxy Statement on Form DEFA on December 28, 2011, Commission File No. 000-15905)
10.5	Management Agreement by and between Lazarus Energy Holdings, LLC, Lazarus Energy, LLC and Blue Dolphin effective as of February 15, 2012 (incorporated by reference to Exhibit 10.2 filed with Amendment No. 1 to Blue Dolphin’s Form 8-K on March 14, 2012, Commission File No. 000-15905)
10.6	Amendment No. 1 to Management Agreement dated May 12, 2014 by and among Lazarus Energy Holdings, LLC, Blue Dolphin and Lazarus Energy, LLC (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 8-K on May 16, 2014, Commission File No. 000-15905)

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Exhibit List

10.7	Promissory Note between Lazarus Energy LLC as maker and Notre Dame Investors Inc. as Payee in the Principal Amount of $8,000,000 dated June 1, 2006 (incorporated by reference to Exhibit 10.6 filed with Blue Dolphin’s Form 10-Q on March 31, 2012, Commission File No. 000-15905)
10.8	Subordination Agreement effective August 21, 2008 by Notre Dame Investors, Inc. in favor of First International Bank (incorporated by reference to Exhibit 10.2 filed with Blue Dolphin’s Form 10-Q on March 31, 2012, Commission File No. 000-15905)
10.9	Intercreditor and Subordination Agreement dated September 29, 2008 by and between Notre Dame Investors, Inc., Richard Oberlin, Lazarus Energy LLC and First International Bank (incorporated by reference to Exhibit 10.3 filed with Blue Dolphin’s Form 10-Q on March 31, 2012, Commission File No. 000-15905)
10.10	Intercreditor and Subordination Agreement dated August 12, 2011 by and among John H. Kissick, Lazarus Energy LLC and Milam Services, Inc. (incorporated by reference to Exhibit 10.7 filed with Blue Dolphin’s Form 10-Q on March 31, 2012, Commission File No. 000-15905)
10.11	First Amendment to Promissory Note by and between Lazarus Energy, LLC and John H. Kissick effective as of July 1, 2013 (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 10-Q on November 14, 2013, Commission File No. 000-15905)
10.12	Second Amendment to Promissory Note by and between Lazarus Energy, LLC and John H. Kissick effective as of October 1, 2014 (incorporated by reference to Exhibit 10.48 filed with Blue Dolphin’s Form 10-K on March 31, 2015, Commission File No. 000-15905)

10.13	Second Amendment to Promissory Note by and between Lazarus Energy, LLC and John H. Kissick effective as of October 1, 2014 (incorporated by reference to Exhibit 10.48 filed with Blue Dolphin’s Form 10-K on March 31, 2015, Commission File No. 000-15905)
10.14	Loan Agreement among Sovereign Bank, Lazarus Energy, LLC and Jonathan Pitts Carroll, Sr., Blue Dolphin Energy Company, Lazarus Refining & Marketing, LLC, and Lazarus Energy Holdings dated June 22, 2015 (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.15	Promissory Note between Lazarus Energy, LLC and Sovereign Bank for the principal sum of $25,000,000 dated June 22, 2015 (incorporated by reference to Exhibit 10.2 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.16	Security Agreement of Lazarus Energy, LLC in favor of Sovereign Bank dated June 22, 2015 (incorporated by reference to Exhibit 10.3 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.17	Deed of Trust, Mortgage, Security Agreement, Assignment of Leases and Rents, Financing Statement and Fixture Filing for Lazarus Energy, LLC dated June 22, 2015 (incorporated by reference to Exhibit 10.4 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)

10.18	Security Agreement of Lazarus Energy, LLC for the benefit of Lazarus Refining & Marketing, LLC dated June 22, 2015 (incorporated by reference to Exhibit 10.5 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.19	Loan and Security Agreement between Sovereign Bank and Lazarus Refining & Marketing, LLC dated June 22, 2015 (incorporated by reference to Exhibit 10.6 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.20	Pledge Agreement by Lazarus Refining & Marketing, LLC in favor of Sovereign Bank dated June 22, 2015 (incorporated by reference to Exhibit 10.8 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.21	Collateral Assignment executed by Blue Dolphin Pipe Line Company for the benefit of Sovereign Bank dated June 22, 2015 (incorporated by reference to Exhibit 10.9 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.22	Guaranty Agreement by Jonathan Pitts Carroll, Sr., Blue Dolphin Energy Company, Lazarus Energy, LLC and Sovereign Bank dated June 22, 2015 (incorporated by reference to Exhibit 10.10 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)

76

Exhibit List

10.23	Guaranty Fee Agreement between Jonathan P. Carroll and Lazarus Energy, LLC dated June 22, 2015 (incorporated by reference to Exhibit 10.11 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.24	Guaranty Fee Agreement between Jonathan P. Carroll and Lazarus Refining & Marketing, LLC dated June 22, 2015 (incorporated by reference to Exhibit 10.12 filed with Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No. 000-15905)
10.25	Amendment No. 2. to Operating Agreement by and between Lazarus Energy Holdings, LLC, Blue Dolphin, and Lazarus Energy, LLC effective as of June 1, 2015 (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 10-Q on August 14, 2015, Commission File No. 000-15905)
10.26	Loan Agreement among Sovereign Bank, Lazarus Refining & Marketing, LLC, Jonathan Pitts Carroll, Sr., Blue Dolphin Energy Company, Lazarus Energy, LLC, and Lazarus Energy Holdings dated December 4, 2015 (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.27	Promissory Note between Lazarus Refining & Marketing, LLC and Sovereign Bank for the principal sum of $10,000,000 dated December 4, 2015 (incorporated by reference to Exhibit 10.2 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.28	Security Agreement of Lazarus Refining & Marketing, LLC in favor of Sovereign Bank dated December 4, 2015 (incorporated by reference to Exhibit 10.3 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.29	Deed of Trust, Mortgage, Security Agreement, Assignment of Leases and Rents, Financing Statement and Fixture Filing for Lazarus Refining & Marketing, LLC dated December 4, 2015 (incorporated by reference to Exhibit 10.4 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.30	Construction Rider to Loan Agreement dated December 4, 2015 (incorporated by reference to Exhibit 10.5 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.31	Absolute Assignment of Leases and Rents dated December 4, 2015 (incorporated by reference to Exhibit 10.6 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.32	Indemnification Agreement dated December 4, 2015 (incorporated by reference to Exhibit 10.7 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.33	Pledge Agreement by Lazarus Energy Holdings, LLC in favor of Sovereign Bank dated December 4, 2015 (incorporated by reference to Exhibit 10.8 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.34	Collateral Assignment of Key Agreements dated December 4, 2015 (incorporated by reference to Exhibit 10.9 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.35	First Amendment to Lazarus Energy, LLC Loan Agreement and Loan Documents dated December 4, 2015 (incorporated by reference to Exhibit 10.10 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.36	First Amendment to Lazarus Energy, LLC Deed of Trust, Mortgage, Security Agreement, Assignment of Leases and Rents, Financing Statement and Fixture Filing dated December 4, 2015 (incorporated by reference to Exhibit 10.11 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.37	Guaranty Fee Agreement between Jonathan P. Carroll and Lazarus Refining & Marketing, LLC dated December 4, 2015 (incorporated by reference to Exhibit 10.12 filed with Blue Dolphin’s Form 8-K on December 10, 2015, Commission File No. 000-15905)
10.38	Loan and Security Agreement by and between Lazarus Energy Holdings, LLC and Blue Dolphin Pipe Line Company dated August 15, 2016 (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 8-K on August 19, 2016, Commission File No. 000-15905)
10.39	Promissory Note by and between Lazarus Energy Holdings, LLC and Blue Dolphin Pipe Line Company dated August 15, 2016 (incorporated by reference to Exhibit 10.2 filed with Blue Dolphin’s Form 8-K on August 19, 2016, Commission File No. 000-15905)

10.40 Deed of Trust, Mortgage, Security Agreement, Assignment of Leases and Rents, Financing Statement and Fixture Filing for Blue Dolphin Pipe Line Company dated August 15, 2016 (incorporated by reference to Exhibit 10.3 filed with Blue Dolphin’s Form 8-K on August 19, 2016, Commission File No. 000-15905)

77

Exhibit List

10.41	Collateral Assignment of Master Easement Agreement by Blue Dolphin Pipe Line Company for the benefit of Lazarus Energy Holdings, LLC dated August 15, 2016 (incorporated by reference to Exhibit 10.4 filed with Blue Dolphin’s Form 8-K on August 19, 2016, Commission File No. 000-15905)
10.42	Promissory Note dated March 31, 2017, of Blue Dolphin Energy Company in favor of Lazarus Energy Holdings, LLC (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 10-Q on May 15, 2017, Commission File No. 000-15905)
10.43	Amended and Restated Promissory Note dated March 31, 2017, of Blue Dolphin Energy Company in favor of Ingleside Crude, LLC (incorporated by reference to Exhibit 10.2 filed with Blue Dolphin’s Form 10-Q on May 15, 2017, Commission File No. 000-15905)
10.44	Amended and Restated Promissory Note dated March 31, 2017, of Blue Dolphin Energy Company in favor of Lazarus Capital, LLC (Jonathan Carroll) (incorporated by reference to Exhibit 10.3 filed with Blue Dolphin’s Form 10-Q on May 15, 2017, Commission File No. 000-15905)
10.45	Amended and Restated Operating Agreement effective as of April 1, 2017, between Lazarus Energy Holdings, LLC, Lazarus Energy, LLC, and Blue Dolphin Energy Company (incorporated by reference to Exhibit 10.4 filed with Blue Dolphin’s Form 10-Q on May 15, 2017, Commission File No. 000-15905)
10.46	Amended and Restated Promissory Note dated June 30, 2017, of Blue Dolphin Energy Company in favor of Lazarus Energy Holdings, LLC (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 10-Q on October 12, 2017, Commission File No. 000-15905)
10.47	Amended and Restated Guaranty Fee Agreement between Jonathan Carroll and Lazarus Refining & Marketing, LLC (incorporated by reference to Exhibit 10.2 filed with Blue Dolphin’s Form 10-Q on October 12, 2017, Commission File No. 000-15905)
10.48	Amended and Restated Guaranty Fee Agreement between Jonathan Carroll and Lazarus Refining & Marketing LLC (incorporated by reference to Exhibit 10.3 filed with Blue Dolphin’s Form 10-Q on October 12, 2017, Commission File No. 000-15905)
10.49	Amended and Restated Guaranty Fee Agreement between Jonathan Carroll and Lazarus Energy, LLC (incorporated by reference to Exhibit 10.4 filed with Blue Dolphin’s Form 10-Q on October 12, 2017, Commission File No. 000-15905)

10.50 Line of Credit, Guarantee and Security Agreement among Pilot Travel Centers LLC, Nixon Product Storage, LLC and the other loan parties hereto dated as of May 3, 2019 (as amended and restated as of May 9, 209 and May 10, 2019) (incorporated by reference to Exhibit 10.2 filed with Blue Dolphin’s Form 10-Q on August 14, 2019, Commission File No. 000-15905)

10.51	Pledge Agreement between Pilot Travel Centers LLC and Blue Dolphin Energy Company dated as of May 3, 2019
	(incorporated by reference to Exhibit 10.3 filed with Blue Dolphin’s Form 10-Q on August 14, 2019, Commission File No. 000-15905)

10.52	First Amendment and Restatement Agreement among Pilot Travel Centers LLC, Nixon Product Storage, LLC and the other loan parties hereto dated as of May 9, 2019 (incorporated by reference to Exhibit 10.4 filed with Blue Dolphin’s Form 10-Q on August 14, 2019, Commission File No. 000-15905)
10.53	Second Amendment and Restatement Agreement among Pilot Travel Centers LLC, Nixon Product Storage, LLC and the other loan parties hereto dated as of May 10, 2019 (incorporated by reference to Exhibit 10.5 filed with Blue Dolphin’s Form 10-Q on August 14, 2019, Commission File No. 000-15905)

10.54	Pledge Agreement between Pilot Travel Centers LLC and Blue Dolphin Energy Company dated as of May 3, 2019
	(incorporated by reference to Exhibit 10.6 filed with Blue Dolphin’s Form 10-Q on August 14, 2019, Commission File No. 000-15905)

10.55	Notice from Veritex Community Bank to Lazarus Energy, LLC, Blue Dolphin Energy Company, Lazarus Refining & Marketing, LLC, Lazarus Energy Holdings, LLC, Lazarus Marine Terminal I, LLC and Jonathan Pitts Carroll, Sr. dated April 30, 2019 (incorporated by reference to Exhibit 10.7 filed with Blue Dolphin’s Form 10-Q on August 14, 2019, Commission File No. 000-15905)
10.56	Amendment No. 1 to Line of Credit, Guarantee and Security Agreement among Pilot Travel Centers LLC, Nixon Product Storage, LLC and the other loan parties hereto dated as of September 3, 2019 (incorporated by reference to Exhibit 10.1 filed with Blue Dolphin’s Form 10-Q on November 14, 2019, Commission File No. 000-15905)

78

Exhibit List

14.1 Code of Ethics applicable to the Chairman, Chief Executive Officer and Senior Financial Officer (incorporated by reference to Exhibit 14.1 filed with Blue Dolphin’s Form 10-KSB on March 25, 2005, Commission File No. 000-15905)

21.1** List of Subsidiaries of Blue Dolphin

23.1** Consent of UHY LLP

31.1** Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002

32.1** Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002

99.1	Amended and Restated Audit Committee Charter as reviewed by the Board of Directors of Blue Dolphin on November 15, 2018 (incorporated by reference to Appendix A filed with Blue Dolphin’s Proxy Statement on Form DEF 14A on November 15, 2018, Commission File No. 000-15905)
99.2	Compensation Committee Charter as reviewed by the Board of Directors of Blue Dolphin on November 15, 2018 (incorporated by reference to Appendix B filed with Blue Dolphin’s Proxy Statement on Form DEF 14A on November 15, 2018, Commission File No. 000-15905)

101.INS** XBRL Instance Document

101.SCH** XBRL Taxonomy Schema Document

101.CAL** XBRL Calculation Linkbase Document

101.LAB** XBRL Label Linkbase Document

101.PRE** XBRL Presentation Linkbase Document

101.DEF** XBRL Definition Linkbase Document

_______________

*    Management Compensation Plan

**  Filed herewith

Remainder of Page Intentionally Left Blank

79

Signature Page

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BLUE DOLPHIN ENERGY COMPANY
	(Registrant)
March 30, 2020	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer, Principal Financial Officer, and Principal Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ JONATHAN P. CARROLL
Jonathan P. Carroll	Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer, Principal Financial Officer, and Principal Accounting Officer)	March 30, 2020
/s/ RYAN A. BAILEY
Ryan A. Bailey	Director	March 30, 2020
/s/ AMITAV MISRA
Amitav Misra	Director	March 30, 2020
/s/ CHRISTOPHER T. MORRIS
Christopher T. Morris	Director	March 30, 2020
/s/ HERBERT N. WHITNEY	Director	March 30, 2020
Herbert N. Whitney

80